IR 05000272/1990019

Insp Repts 50-272/90-19,50-311/90-19 & 50-354/90-14 on 900619-0815.Noncited Violations Noted.Major Areas Inspected: Operations,Radiological Controls,Maint & Surveillance Testing,Emergency Preparedness & Security

ML18095A467
Person / Time
Site:	Salem, Hope Creek
Issue date:	09/04/1990
From:	Swetland P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML18095A466	List: IR 05000272/1990019 ML18095A465
References
50-272-90-19, 50-311-90-19, 50-354-90-14, NUDOCS 9009140121
Download: ML18095A467 (52)

Text

Report No License No Licensee:

Facilities:

Dates:

Inspectors:

U. S. NUCLEAR REGULATORY COMMISSION

REGION I

50-272/90-19 50-311/90-19 50-354/90-14 DPR-70 DPR-75 NPF-57 Public Service Electric and Gas Company P. 0. Box 236 Hancocks Bridge, New Jersey 08038 Salem Nuclear Generating Station Hope Creek Nuclear Generating Station June 19, 1990 - August 15, 1990 Thomas P. Johnson, Senior Resident Inspector David K. Allsopp, Resident Inspector Stephen M. Pindale,.Resident Inspector Stephen T. Barr, Resident Inspector Henry K. Lathrop, Resident Inspector Ronald L. Nimitz, Senior Radiation Specialist Herbert J. Kaplan, Senior Reactor Engineer Approved:

~P. Inspection Summary:

Inspection 50-272/90-19; 50-311/90-19; August 15, 1990 f/f"bo Projects Section 2A

'bate 50-354/90-14 on June 19, 1990 -

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Areas Inspected:

Resident safety inspection of the following areas:

operations, radiological controls, maintenance & surveillance testing, emergency preparedness, security, engineering/technical support, safety assessment/quality verification, and licensee event reports and open item followu Results:

The inspectors identified 5 non-cited violations for the Salem and Hope Creek station Two unresolved items were identified at Salem regarding the process by which reactor coolant system leakage rates are calculated and the methodology used to predict intermediate range nuclear instrumentation trip setpoint An executive summary fol lows.

90091401?1 900904

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P_-.JDR Ati~_,j_--:i~.. * - c:-

r (_)._r000272 PDC I. SUMMARY Salem Inspection Reports 50-272/90-19; 50-311/90-19 Hope Creek Inspection Report 50-354/90-14 June 19, 1990 - August 15, 1990 Operations (Modules 71707, 71711, 60710, 93702)

Salem:

Good operator actions were noted during the Unit 2 reactor trip that was caused by a non-safety related transformer failur However, two of four main steam isolation valves failed to clos Several tagging system implemen-tation problems were identified by the license Service water system leaks and radiation monitor actuations were properly identified, reported and resolve A Unit 1 main steam isolation actuation during heatup was similar to several previous event Licensee actions for a Technical Specification 3. entry for inoperable rod position were adequat Hope Creek:

The licensee identified that tagging system implementation problems combined with poor return to service activities, caused a reactor water cleanup isolatio Good operator response was noted when the loss of a vital bus caused a loss of reactor feed pump even Non-conservative operation was noted relative to redundant safety equipment being out of servic The inspector noted a minor weakness in the licensee's procedure for documenting out of service control room indication Safety relief valve cycle counter circuits were noted as being not reset to zer Licensee response was adequate for these issue Radiological Controls (Modules 71707, 83750, 93702)

Salem:

Two non-cited violations were noted:

(1) there were several examples of loss of control of radioactive contaminated material; and, (2) uncontrolled radiation check sources were found at the training cente Hope Creek:

Licensee actions in response to a radioactive spill resulting from overflowing tanks in the Radwaste building were appropriat Maintenance/Surveillance (Modules 61726, 62703)

Salem:

The licensee 1 s process for calculating reactor coolant system leakage rates is unresolve Licensee identification of missed surveillances due to ineffective administrative control and an incorrect technical specification setpoint for a nuclear instrumentation permissive (P-6) are non-cited viola-tion Hope Creek:

Licensee identification of a missed surveillance due to a personnel error by a supervisor is a non-cited violation.

i

• Emergency Preparedness (Module 71707)

A loss of the ENS phone for both Hope Creek and Salem was adequately responded to by the license Security (Module 71707, 93702)

Security program audits by QA were noted as being thorough and well documente Engineering/Technical Support (Modules 71707)

Salem:

Specific vendor correspondence related to potential auxiliary feedwater overspeed trip device problems were determined to be not applicable; licensee followup was thorough and proactiv A metallurgical report for limitorque motor pinion key failures was adequat Licensee review of a Westinghouse part 21 report concerning the reactor protection system was adequat Initial licensee incident report followup for transformer failures was not aggressive; however, further followup by system engineering and a Significant Event Response Team was goo The licensee 1 s methodology for predicting intermediate range nuclear instrumentation trip setpoints was unresolve Hope Creek:

The high pressure coolant injection overspeed trip device reset feature is susceptible to design problem Licensee followup of this vendor information was thorough and proactiv A service wate temporary non-code repair was adequately performed by the license Safety Assessment/Assurance of Quality (Modules 30703, 40500, 71707, 90712, 92700, 92703)

Salem:

Unit 1 was conservatively shutdown due to concerns related to main steam isolation valve performance under specific postulated condition The licensee twice voluntarily entered Technical Specification (TS) 3.0.3 due to inoperability of safety injection for Unit One entry was well planned and implemente However, the other entry did not have the same high level of management attention and oversigh Hope Creek:

Following the Salem events, Hope Creek also twice entered TS 3.0.3 to facilitate a Rosemount transmitter replacemen Both entries were well planned and implemented, with adequate management oversigh Licensee management response to operations with redundant safety equipment being out of service was noted as being aggressiv Common:

Additional administr~tive controls and guidance is required to control voluntary TS 3.0.3 entrie Salem and Hope Creek Station Operations Review Committee 1 s displayed a good questioning attitude directed towards nuclear safety.

ii

• DETAILS SUMMARY OF OPERATIONS 1.1 Salem Unit 1 1. 2 Salem Unit 1 began the report period at 100% powe The unit operated continuously until July 22, 1990, when the reactor was manually shutdown for evaluation of potential deficiencies related to the main steam isolation valves' ability to close under certain postulated condition The unit was placed in Mode 5 (Cold Shutdown)

on July 26, 199 Following resolution of the main steamline isolation valve (MSIV) concerns, mode ascension activities commenced on August 10, 199 The reactor was made critical on August 14, 1990, however, was subsequently shutdown to Mode 3 (Hot Standby) on August 15, 1990 due to control rod indication problem At the end of the inspection, the unit remained in Mode 3 for troubleshooting activitie Salem Unit 2 Salem Unit 2 began the report period with the reactor in Mode 3 (Hot Standby) preparing for startup following the recent refueling and maintenance outag The unit went critical on June 20, 1990.

Reactor physics testing progressed and 75% power was reached on June 27, 199 The reactor tripped automatically on June 28, 1990 following a transformer failure and the resulting loss of feedwate Two of four MSIVs failed to fully close in response to a manually generated isolatio The unit was shutdown to Mode 4 (Hot Shutdown)

on June 30, 1990 for MSIV testing and repair On July 25, 1990 the unit was placed in Mode 5 due to additional concerns related to the MSIV The MSIV issues were subsequently resolved, and the unit prepared for mode ascensio At the end of the inspection, Unit 2 was in Mode 3.and preparing for reactor restar Hope Creek The Hope Creek unit began the report period at 100% power and, except for two brief power reductions needed to perform maintenance activi-ties, the unit remained at full power throughout the perio Power was reduced to 60% for approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> on July 7, 1990 in order to repair the number 2 main turbine control valve, which had begun to open and close sporadically due to loose wire connections in its control circuitr On August 4, 1990, power was reduced to 40%

for approximately two hours so that the plant could be placed in single loop operation in order to perform maintenance on the 11811 recirculation motor generator se * *

OPERATIONS Inspection Activities The inspectors verified that the facilities were operated safely and in conformance with regulatory requirement 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 Limiting Conditions for Operation, and review of facility record These inspection activities were conducted in accordance with NRC inspection procedures 60710, 71707, 71711 and 9370 The inspectors performed normal and back shift inspection, including deep backshift inspection as follows:

Unit Inspection Hours Dates Salem 7:30 a.m. -

1:30 P,* July 21, 1990 7:30 a.m. - 12:30 p. July 22, l990 Hope Creek None Inspection Findings and Significant Plant Events 2. Salem Unit 2 Reactor Trip on June 28, 1990 On June 28, 1990 at 12:32 a.m., during power ascension operations, a Unit 2 reactor trip occurred as a result of the loss of both steam generator feedwater pumps (SGFPs).

The loss of the SGFPs was preceded by the failure of the 2F 4160 to 480 Volt Transforme With the loss of both SGFPs, an automatic reactor trip on 11 low steam generator level coincident with steam flow/feed fl ow mi smatch 11 actuate The reactor protection system functioned as designe Following the reactor trip, a main steamline isolation was manually initiated to reduce a high cooldown rat However, two of the four main steam isolation valves (21 and 24MS167) did not close on the first attemp The operator again depressed the main steamline isolation pushbuttons and this time received a closure indication for the valves on the consol The unit was then stabilized in Mode 3 (Hot Standby).

This event raised a concern regarding the main steamline isolation control circuit logic design (see NRC Inspection 50-272/90-20; 311/90-20).

• The inspectors reviewed the event including operator respons The inspector determined that the reason a steam line isolation was required by the emergency procedures was due to excessive auxiliary feedwater (AFW) system flo The flow control valves are set such that the measured flow greatly exceeds that required per design specification Licensee efforts were continuing to determine a permanent resolution of the AFW high flow rate concerns, and will be reviewed by the inspector during a subsequent inspectio Service Water (SW) System Leaks The licensee identified SW through wall lea ks as fo 11 ows:

Unit Component Time/Date

Component cooling 1:00 p.m./July 2, 1990 water flange

Auxiliary feedwater (AFW) room cooler 11:15 a.m./July 5, 1990

14 Containment Fan 10:40 a.m./July 23, 1990 Cooling Unit (CFCU)

21/22 SW Chillers 5:00 p.m./July 23, 1990

11 SW pump casing 5:50 a.m./July 28, 1990

12 CFCU 4:40 p.m./August 1, 1990

.1 AFW steam supply 6:50 p.m./August 14, 1990 drain line valve For each occurrence the leak was minimized or isolated, an ENS call was made and the inspector notified, an incident report was written to investigate cause(s),

and the leak was repaire The inspector reviewed each occurrence including licensee action Discussions were held with licensee personne The inspector concluded that licensee actions were appropriate and -

the inspector had no further questions at this tim Radiation Monitor Engineered Safety Feature (ESF)

Actuations The following ESF actuations occurred and were reported by the licensee during the period:

• D.

Unit

2

2

Radiation Monitor Date/Time Control Room ( lRlB)

Containment (2R12A)

Gas Plant Ventilation (2R45C)

Containment Ventilation (2R41C)

11:09 p.m./July 1, 1990 9:15 a.m./August 6, 1990 8:01 a.m./August 7, 1990 3:52 a.m. & 12:39 p.m./

August 8, 1990 10:11 a.m./July 3, 1990 1:20 p.m./June 28, 1990 2:02 p.m./August 9, 1990 The inspector reviewed licensee actions regarding these event The licensee intends to submit an LER for these event No unacceptable conditions were note Unit 1 Service Water (SW) Leak On August 1, 1990, at about 5:00 a.m., SW leaked into the Unit 1 No. 11 SW Bay in the auxiliary buildin The leak was through an opened SW check valve 11SW5 SW51 had been released by operations for inspection by maintenanc Approximately 20,000 gallons entered the bay and several inches of water were on the auxiliary building 78 foot level floo The SW leak path was isolated and the licensee inspected the area for damag No damage was foun The floor was cleaned up and released about noon that same da The licensee's root cause review of the event concluded the following items:

Work control supervisors had access to the Tagging Request Information System (TRIS) computer data base such that 11 standard 11 (pre-approved) tagging requests could be changed or modifie * *

The Nuclear Shift Supervisor did not perform a detailed review of the tagout because it was 11 standard. 11 Poor communications occurred between the reactor operators in the control room and the equipment operators in the field, resulting in failure to follow special instructions on the tagou As a result, an inadequate tagout was created by the TRIS computer, approved by the Nuclear Shift Supervisor and implemented by operator Several lines of defense (supervision, reactor and equipment operators) broke down during this tagging evolution, resulting in the SW leak into the Unit 1 auxiliary buildin The inspector reviewed the licensee's investigation and root cause analysi The inspector concluded it was thorough, timely and complet Adequate corrective actions were either performed or planne The inspector examined the affected auxiliary building areas and equipmen The inspector discussed the event with licensee operations and management personne The in~pector had no further questions at this time.

Subsequent to this event, three additional examples of plant events, possibly due to tagging deficiencies, occurred at the Salem units on August 12, 199 The licen~ee formed a task force comprised of Operations, Maintenance, Quality Assurance and Planning personnel to identify the root causes of the events and to determine whether there were common factor The inspector will review the results of this investigation during a future inspectio Unit 1 Main Steam Line (MSL) Isolation On August 12, 1990, during reactor heatup with the residual heat removal system in service, Unit 1 received a MSL isolation signal due to spurious high steam flow signal The unit was in Mode 4 (Hot Shutdown) at the time of the isolatio The bistables associated with one high steam flow channel for each of two (of four) steam generators (Nos. 11 and 12)

actuated spuriousl The isolation logic was satisfied when two high steam flow channels associated with the two steam generators tripped coincident with reactor coolant average temperature less than 543 degrees F and main steam pressure less than 600 psi The main steam isolation valves (MSIVs) and associated bypass valves were closed prior to the actuatio The four MSL drain valves were open and went closed as expecte *

• *

Immediately following the MSL isolation, plant operators noticed that the solid state protection system MSL isolation indication lights and an overhead annunciator were not illuminated for loop No. 13 (Train A and 8).

The MSL valves had closed as require Subsequent investigation identified that a closed limit switch on the 13 MSIV was not satisfied, which resulted in the noted abnormal control room indication It was also determined that one of the two MSIV steam vent valves (13MS171) associated with loop 13 was open and discharging steam to the atmospher That was also attributed to the loop 13 MSIV closed limit not being satisfie The limit switch was subsequently adjusted and the proper indications were receive A similar MSL isolation occurred at Unit 1 while in Mode 4 on June 3, 1990 and was determined to be due to an uneven heatup of the steam flow sensing line The licensee currently plans to pursue corrective actions, including possible design modifications, to address the heatup phenomeno The inspector reviewed the event and interviewed licensee personnel, and had no further question The LER will be reviewed in a future inspection.

Plant Shutdown Due to Inoperable Rod Indication On August 14, 1990, the Unit 1 reactor achieved criticality at 7:24 Subsequently, several analog control rod individual rod position indicators (IRPis)

drifted outside their allowable indication limit Technical Specification (TS) 3.1.3.2.1 requires that specific action must be taken with more than one analog IRPI per control rod bank inoperabl Several IRPis were declared inoperable because they indicated a position deviation greater than 12 steps from the group demand counter Three control and shutdown control rod banks had more than one inoperable IRP Therefore, TS 3.0.3 was entered at 11:55 p.m., and a unit shutdown to Mode 3 (Hot Standby) commence Mode 3 was entered at 12:57 a.m. on August 15, 199 The licensee notified the NRC of the unit shutdown in accordance with 10CFR50.72 reporting requirements.

• 2. *

Followup review by the inspector determined that a total of seven IRPis were declared inoperabl The licensee obtained primary voltage readings at the time of the event and determined that the group demand counters were accurate and the IRPis had drifted for unknown reason !RPI drifts have occurred in the past, however, the IRPis were able to be adjusted to within specification On August 15, 1990, the licensee calibrated all control rods; only minor adjustments were require System engineering was also involved in determining the cause of the observed problem The inspector had no further questions at this tim Hope Creek Reactor Water Cleanup (RWCU) Isolation on June 28, 1990 (LER 90-010)

On June 28, 1990, an engineered safety feature (ESF)

actuation occurred at Hope Creek when an RWCµ isolation was caused by a high differential flow signa The isolation signal was generated while operato~s were placing the 11A 11 RWCU pump in service following scheduled maintenanc The operators reset the isolation and placed the 118 11 RWCU pump, which had been operating prior to the isolation, back into operatio Subsequent licensee troubleshooting efforts revealed that the high differential flow signal occurred because two drain valves downstream of the 11A 11 pump and upstream of the pump discharge valve were open when the pump was starte Once the cause of the isolation was determined, the drain valves were shut, the RWCU containment isolation valve was reopened and the 11A

RWCU loop was placed in servic The on-duty Senior Nuclear Shift Supervisor initiated a four hour non-emergency report to the NRC in accordance with station procedures and lOCFRS0.72 due to the ESF initiation involved with this even The licensee determined the primary cause of the event was inadequate verification of the RWCU system alignment following the maintenance that had been performed on the 11A 11 1 oo Factors which were determined to contribute to the cause included erroneous implementation of the safety tagging system relative to the RWCU system maintenance, the absence of drain valve position verification in the operating procedure for returning the RWCU system to service, and inadequate verification of RWCU system alignment

• following the release of the safety tagging reques The inspector learned that a similar event involving these RWCU drain valves occurred in September 1987, and as a result, tagging philosophies were changed to include tagging of all vent and drain valves within the tagging request boundar The licensee stated that in this incident, however, a conscious decision was made not to include the drain valves in the tagging request because maintenance on the valves was scheduled during the system outag Corrective actions taken by the licensee in response to this event included reviewing the event with ail Operations Department personnel, revising the RWCU operating procedure and the equipment restoration administrative procedure to ensure proper position verification of all vent and drain valves within a tagging request boundary, and revising the safety tagging system administrative procedure to ensure all special instructions and deviations involved with the tagging of a system are noted on the hand written tagging request form and entered into the computer system tagging reques *

The inspector discussed this event and the corrective actions with several Nuclear Shift Supervisors that function as work control center supervisors and coordinate system tag-outs, and all believed the corrective actions will help to prevent recurrence of

~imilar event In reviewing this event, the inspector concluded that, while the original system misalignment could have been avoided, operator response to the event was proper and corrective actions taken by the licensee were adequat Momentary Loss of the 11 C 11 Vital Bus on July 10, 1990 At 9:33 a.m. on July 10, 1990, with the unit at 100%, a momentary loss of the 11 C 11 4160 volt vital bus (403 bus)

occurred during surveillance testin The 40301 alternate supply breaker was closed by the operator for the test and the breaker then immediately trippe The normal feeder breaker 40308 opened per design when the 40301 breaker closed, and subsequently reclosed to re-energize the 403 bu *

The momentary vo*ltage transient on the 403 bus caused the following equipment actions:

11 C 11 reactor feed pump (RFP) turbine tripped, 11C 11 service water pump tripped, 11 C 11 safety auxiliary cooling system (SACS) pump tripped, Turbine building chillers tripped, and Turbine auxiliary cooling system (TACS) swapped to the alternate SACS loop on low system pressur The operators responded by manually reducing reactor recirculation flow to a corresponding value of 95%

reactor power to prevent loss of reactor water leve Water level decreased from a normal level of 35 inches to 31 inche This action prevented an automatic recirculation runback to an even lower power leve The 118 11 SACS and 118 11 service water pumps were also starte This response was in accordance with abnormal operating procedures for feedwater malfunction, loss of SACS and loss of TAC Troubleshooting activities identified a faulty logic card for the 40301 breaker control circui Repairs were made and retest activities were satisfactorily performe The 11 C 11 RFP was returned to service and reactor power was increased to 100%.

The inspector toured the control room approximately 1 1/2 hours after this even The inspector examined control room indications and chart recorder traces, interviewed the operators, reviewed logs and abnormal operating procedure The inspector concluded that the licensee actions were appropriate, in accordance with procedures, and effective in minimizing the severity of the transien Redundant Safety Equipment Out of Service During a morning tour of the Hope Creek control room at 7:00 a.m. on July 17, 1990, the inspector noted that the 11A 11 diesel generator (DG) was out of service for maintenanc The 11A 11 DG had been removed for planned preventive and corrective maintenance activities at 3:00 a.m. on July 17, 199 One DG out of service required entry into 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Technical Specification Action Statement (TSAS) 3.8.1. Previously, the 11c11 low pressure coolant injection (LPCI) system pump had been declared inoperable on July 8, 1990 due to water in the motor oi One LPCI pump out of service required entry into 30 day TSAS 3.5.1. *

The inspector questioned the control room operators at shift turnover and operations management at the morning meeting on July 17, 1990 regarding redundant safety equipment being out of service, e.g., the 11N1 DG and the 11C 11 LPCI pum The inspector was informed that the 11 C 11 LPCI pump had been tested the previous shift and was availabl However, the failure of a flow isolator electrical device prevented the formal completion of the surveillance test and declaration of LPCI pump operabilit Repairs were completed to the card and 11 C 11 LPCI pump was declared operable at 10:00 a.m. on July 17, 199 The inspector reviewed TS and TSAS including the definition for operabilit Hope Creek TSs does not have standard paragraph 3.0.5 which states that if an emergency power source is unavailable for a train, it may be considered operable if redundant trains are operabl With the 11A 11 DG inoperable, and b.ecause of known inoperability of the 11 cu LPCI pump would place the unit into a 7 day TSAS 3.5.1.b.2 with 2 LPCI pumps out of servic The licensee stated that the current 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> TSAS was more limiting than the 7 day TSAS with 2 LPCI pumps inoperable.

The in?pector questioned plant and operations management regarding the philosophy of voluntarily removing redundant safety equipment from servic Plant management had also expressed concern with the operating shift regarding this activit The licensee stated that this was not the normal practice and the issue was discussed with responsible operations personne The inspector was informed of TS interpretation (TSI) 3.8.1.2 regarding AC power sources while shutdown (Modes 4 and 5 only).

This TSI limits DGs removed from service during outage and shutdown condition The licensee was pursuing a TSI to be applicable for operating condition The inspector concluded that the licensee was withiri their TS requirement However, voluntary removal of redundant safety equipment is not considered to be a conservative operating practic The inspector also noted that licensee management response to this issue was aggressiv *

11 High Pressure Coolant Injection (HPCI) System Isolation Valve Deficiency During surveillance testing at 2:50 a.m. on July 19, 1990, the licensee identified a broken terminal lug which would have prevented HPCI isolation on a HPCI high steam flow isolation signa While -I&C personnel were performing HPCI high steam flow test IC-FT.FD-001 on HPCI high steam flow isolation, they found a relay contact that was not energizin Non energization (contact not closing) of this relay would prevent the HPCI inboard isolation valve E41-F002 from isolating on a HPCI high steam flow signa The licensee found a broken terminal lug on relay E41Kl5 The terminal lug was replaced and the test reperformed satisfactoril HPCI was inoperable for approximately 2.5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> The reactor core isolation cooling (RCIC) system and all other emergency cooling systems were operabl The licensee speculated that this terminal lug might have been broken the last time that I&C performed this monthly functio~al test because the affected terminal is used to perform the test.

The inspector verified licensee actions and reviewed incident report 90-08 The licensee has been pursuing a modification/design change package (DCP) to install permanent test connections to test point terminal lugs that would prevent this type of failur This DCP is scheduled for partial implementation during the upcoming refueling outag The inspector had no further questions at this tim Out of Service/Deficient Control Room Indications The licensee uses a daily log (DL) to document out of service control room instruments and alarm Daily log No. 10 (DL-010) tracks these deficiencies with associated work order numbers and other related informatio Out of service indications are denoted by placing a piece of red tape diagonally over the appropriate control room instrument/alar The licensee addresses any TS instrument operaqility issues by use of the TS action statement lqg (HC.OP-AP.ZZ-0108).

• During the period, the inspector noted that the full core display for a control rod position was incorrect in that the green (full in) light was illuminate The rod was verified to be full out by the four group rod position indications by the process computer, and by the local power range monitor The inspector questioned operations personnel and noted they were all knowledgeable of the discrepanc However, the inspector questioned why the condition was not denoted in DL-01 The licensee stated that the DL-010 was for control room instruments/alarms that were out of servic However, they agreed that any out of service control room indications should also be include The licensee committed to revise DL-010 procedure The inspector had no further questions at this tim Also during the period, the inspector noted that several safety relief valve (SRV) count circuits were not reset to zer The count circuit indicates the number of SRV cycle The inspector confirmed that these count circuits are re-zeroed during instrument surveillance testin The licensee reset the count circuits and began periodic monitorin The licensee was unable to explain the cause of the spurious cycles or count The licensee stated that any SRV opening would be indicated by the GETARS computer and other available control room indication The licensee added the SRV count circuit indications to a daily lo The inspector had no further questions at this tim RADIOLOGICAL CONTROLS Inspection Activities PSE&G 1 s conformance with the radiological protection program was verified on a periodic basi These inspection activities were conducted in accordance with NRC inspection procedures 71707 and 9370.2 Inspection Findings and Review of Events 3. Salem Routine Observations The inspector observed control point exit procedures to confirm actions were consistent with procedure RP-20 Betamax whole body and portable frisking techniques were reviewe The inspector also interviewed selected technicians and worker Licens.ee actions were noted to be consistent with requirements and no unacceptable conditions were note * *

The inspector observed personnel wearing dosimetry in the radiological control area (RCA).

No unacceptable conditions were note The inspector also verified that personnel in non-RCAs did not cross any RCA boundarie Selected individuals were interviewed and no deficiencies were note Radioactive and Contaminated Material Control The inspector reviewed two events involving the identification, by the licensee, of radioactive or contaminated material that had been either improperly released from the radiological controlled area (RCA) or had been stored outside the RCA without appropriate controls being in effec B.l Contaminated Shoe Released from the RCA On May 2, 1990, at about 11:30 p.m., a worker, who had been working inside the Salem Unit 1 containment, attempted to exit the RCA out alarmed the whole body frisker at the control poin (Also see NRC Inspection 50-272/90-13).: The licensee's radiological controls personnel responded to the alarm, performed a whole body frisk of the worker, and noted radioactive contamination on the worker's shorts and tee shirt of up to 50,000 disintegrations per minute (dpm)

as measured on contact with a thin window Geiger-Mueller (GM) detecto The individual showered four times removing essentially all contamination with the exception of a small spot of contamination on the worker's right kne Since considerable effort had been exercised in attempting to decontaminate the worker's knee, the licensee's radiological control personnel elected to release the individual from the RC The licensee prohibited reentry of the individual into the RCA and advised the worker to return for additional evaluation prior to exiting the station at the end of his shif The worker was allowed to exit the RCA at 1:30 a.m. on May 3, 199 The worker's right knee, measured about 10,000 dpm (small spot).

The worker placed a small plastic bag over the area in an apparent effort to sweat the radioactive contamination out of the skin.

• However, unknown to the licensee, the radiological controls personnel either failed to perform or performed an inadequate contamination survey of the worker 1s shoes prior to the shoes being released from the RC The worker 1s shoes were apparently passed over the RCA boundary by an unknown individua The subsequent contamination measurements, on contact with a GM detector, of the left boot indicated about 300,000 dpm (one inch square spot).

The licensee's limit is 100 counts per minute above back ground which is equivalent to about 1,000 dp The individual returned to the RCA control point near the end of his shift, the knee was re-frisked and found to have only 1,000 dpm on the left knee and the worker was allowed to leave the statio The worker was informed by radiological controls personnel to return to the RCA control point for frisking when he. returned for wor On the way out of the protected area, the worker alarmed the whole body portal monitor at the security guard statio The guards detained the worker and informed radiological controls personne Because the worker was known to have exhibited fixed contamination on his left knee, the radiological controls personnel informed the security guards to allow the individual to exit the statio The worker returned to work and went to the RCA cuntrol point as directed. The worker reentered the whole body frisker at 7:00 p.m. on May 3, 1990, and alarmed it. Subsequent surveys of the worker identified the 300,000 dpm spot of contamination on the worker 1 s left sho The licensee immediately recognized that the contamination had left the RCA and initiated a Radiological Occurrence Repor The licensee initiated the following actions:

The resident inspector was informed on May 3, 199 The licensee revised procedures to require only senior level or properly qualified licensee personnel to perform frisking of materials for final.release (All appropriate personnel were trained in the procedure changes).

The licensee indicated the shoes may have been frisked out by a contractor junior technician, trained in frisking

techniques, but without supervisor revie The licensee was unable to determine how the shoes got across the RCA boundar The licensee revised personnel decontamination procedures to specify what actions should be taken when residual contamination on personnel is identified (All appropriate personnel were trained in the procedure changes).

The licensee revised procedures to require verification of response to portal alarms at the security station (All appropriate personnel were trained in the changes.)

The licensee performed a skin dose evaluation for the worker (maximum exposure estimated was 52 millirem) due to residual contamination on his kne The licensee estimated the maximum 1 dose to the extremity, due to wearing the contaminated boot to be about 6 millirem.

Since the contamination on the boot was fixed, the licensee concluded that no residual contamination was left outside the RCA and other personnel were not exposed to the materia (Surveys of areas traversed by the worker and the worker's car did not identify any residual contamination.)

The. inspector concluded that the licensee's response to the identified contamination removed from the RCA appeared to be timely, aggressive, and appropriat The inspector noted that Technical Specification 6.11 requires, in part, that radiation protection procedures be prepared consistent with the requirements of 10 CFR 20 and adhered t Radiation Protection Procedure 201, Section 7.6.1, requires that material removed from the RCA be frisked to ensure it meets station release limit Radiation Protection Procedure 205, Section 7.1.1, requires that all areas of contamination on the body or clothing be located and the extent documente Radiation Protection Procedure SC.RP-TI-1001 provides the radiological occurrence report levels in Attachment 2 of the procedur *

The inspector noted that: 1) the worker's shoes were not properly frisked and contamination was released from the RCA; 2) all areas of contamination of clothing and person were not properly documented on the radiological occurrence report in that it was unclear as to the extent of initial skin contamination; and, 3) the radiological occurrence report for this event was not properly classifie The incident was classified at Level 1 when it met the criteria for Level The inspector noted that the above three examples constitute a licensee identified violation of Technical Specification 6.11 and is not being cited because the criteria specified in Section V.G of the Enforcement Policy were satisfied (NON 50-272/90-19-01).

The inspector reviewed the apparent licensee identified violation with respect to the criteria for non-issuance of a Notice of Violation described in 10 CFR Part 2, Appendix A and concluded that the licensee met the five criteria identified therei At the time of the inspection, the licensee was in the process of rewriting the radiological occurrence report procedure to provide enhanced guidanc The following issues were discussed with the licensee:

The licensee's procedure for skin decontamination does not provide adequate guidance to ensure initial skin contamination results are documented for purposes of skin dose evaluatio The licensee is reviewing this matte The radiological occurrence report did not evaluate or identify a root cause of the worker's contaminatio The documentation did not identify corrective actions take Inspector discussions with the licensee's radiological controls personnel indicated however that the licensee modified radiological controls for the job to prevent workers from getting contaminated.

• The worker was able to pass, upon reentering the station, through the portal monitors at the security station without alarming the monitor. The licensee is reviewing this matte The licensee's security procedures do not provide guidance as to what actions to take upon observing workers alarm the whole body portal monitors at the security statio The security force however had been instructed as to what actions to tak The licensee is reviewing this matte The licensee performed surveys of storage location With the exception of five contaminated tools measuring from 1000 dpm to 22,000 dpm found in a tool storage area outside the RCA, no other contamination was foun The release of the tools with contamination in excess of release, limits is also a licensee identified violati6n of procedure RP 201, section 7.6.1 and is considered an additional exampl The licensee's corrective actions for the above matter were applicable to this exampl Identification of Radioactive and Contaminated Material Outside the RCA In early January 1990, the licensee's Quality Assurance (QA) Department personnel identified five metal boxes containing contaminated material such as snubbers, motors, and parts inside the

"carpenter shop.

The shop is located outside the RCA. The material was slightly contaminate On January 15, 1990, the licensee's QA personnel issued a corrective action request because the material was not properly controlled by the licensee's radiological controls progra The material was not controlled in accordance with radiation protection procedure 204 in that the area was not a designated radioactive material storage are The licensee concluded that the material had been taken to the carpenter shop for improved control The material was returned to the RCA, an incident report was initiated, and an investigation of the

root cause of the finding was undertake The licensee also undertook an aggressive search to ensure that no similar concerns existed. The licensee also sent out a memorandum to all station departments to assist in the effort to identify radioactive or contaminated material that may be in other department 1 s possessio The licensee developed a table identifying each instance, what program weakness or error caused the matter, the short term corrective actions, and the long term corrective action Action items were issued to appropriate personnel to correct the identified weaknesse The inspector concluded the licensee 1 s response, to the findings appeared to be timely, aggressive and appropriat The licensee performed dose evaluations where appropriate and concluded no individual received any measurable radiation exposur The licensee 1 s review indicated the following:

Licensed radioactive material (check sources)

was found in spare process radiation monitors in warehouse 13, located outside the RCA, in February 199 The material was not in a designated radioactive material storage area and surveyed monthly as required by radiation protection procedure 80 The licensee removed the monitors and placed them within the RC The licensee concluded that the sources had not been received and surveyed in accordance with radiation protection procedure 90 Licensed radioactive material (neutron detectors) was found at the central receiving warehouse in April 1990. The material had not been surveyed in accordance with radiation protection procedure 901 upon receip The detectors were removed from the warehouse, properly inventoried, and placed in secure storage. The licensee 1 s procedures for procurement did not ensure proper radiological controls were implemente Licensed material (fission chambers) was found in the Salem warehouse in June 199 The licensee 1 s procedures for procurement did not ensure proper radiological controls were implemented. The chambers were transferred to secure, onsite storag *

The licensee concluded that the above events occurred principally due trr weaknesses in radioactive material procurement, receipt, storage, and license control As a result, the licensee initiated broad based corrective actions to address each weakness in terms of both short term and long term corrective action The licensee initiated the following actions:

The licensee issued a memorandum to appropriate departmental personnel to provide immediate guidance as to proper controls to be implemented for procurement, receipt, storage and license controls for radioactive and contaminated materia The licensee initiated procedure rev1s1ons to improve procurement, receipt, storage and control of licensed material. The licensee revised procedure PM-AP.ZZ-220 an PM-AP.ZZ-304 to improve radioactive material receipt and storage controls. The ~icensee is also issuing a new procedure (NAP-29) for control of radioactive material.

The licensee also identified that a contract carrier, who transported contaminated equipment, to another licensed facility, left the site in May 1990, without obtaining the proper documentatio The driver was contacted and the material was returned to the site where the driver was provided proper documentatio The licensee's administrative controls were not adequate to prevent the material from being removed from the site and to ensure conformance to 10 CFR 2 The licensee revised radiation protection procedures RP 901 and 906 to preclude recurrenc These procedures are scheduled to be implemented in August 199 Interim administrative controls are in place to secure the truck trailers from remova The licensee's security group has been requested to review controls for outgoing shipment The licensee's radiation protection procedures developed per Technical Specification 6.11 did not include measures to preclude this occurrence.

• The inspector concluded that the above 5 examples of either failure to implement or establish procedures to procure, receive, and control radioactive material to ensure compliance with 10 CFR 20 was an apparent licensee identified violation of Technical Specification 6.1 This matter is considered an additional example of the licensee identified violation of Technical Specification 6.11 discussed above (3.2.1.B.1).

As discussed above, the licensee took effective short term actions to correct the identified weaknesses and initiated long term actions to improve procedural controls for the radioactive material control program. The inspector 1 s review of the above instances, relative to the criteria in 10 CFR 2, Appendix A, for non-issuance of a Notice of Violation, indicated the licensee met the 5 criteria liste The above licensee identified violation remains open pending NRC review of the licensee 1 s i'llplementation 1 of long term corrective actions as follows:

Implementation of revised radiation protection procedures 901 and 90 Implementation of NAP-29, scheduled October 7' 199 Verification of appropriate training in revised program procedure _Review of cqntrol mechanisms for security release of outgoing shipment The licensee also identified that licensed radioactive material (check sources) was found at the Nuclear Training center in March 199 The material was not being properly inventoried in accordance with the provisions of by-product material license number No. 29-15062-02, dated March 24, 198 The material had been at the training center for about a yea The inspector noted that Condition 15 of the license required that a physical inventory be conducted every 6 months to account for all sources received and that the records of the inventories be maintaine The licensee indicated 4 inventories associated with 2 sources were not performed and documente This is a licensee identified violation of License

• 3.2.2*

A.

No. 29-15062-02 and is not being cited because the criteria specified in Section V.G of the Enforcement Policy were satisfied (NON 50-272/90-19-02).

The material was subsequently inventoried, surveyed and returned to the radiological controlled are The radioactive material was returned to the vendor in June 1990, and the license was terminated on July 31,1990. The inspector reviewed this matter with respect to the criteria for non-issuance of a Notice of Violation, discussed in 10 CFR 2, Appendix A and concluded that the licensee met the 5 criteria specified therei The matter was licensee identified, it was immediately corrected and action was taken to prevent recurrenc There were no previous example Hope Creek Overflow of Radwaste Tanks an~ Resultant Spi~l

. On June 15, 1990, in preparation to recycle !liquid from the A Waite Sample Tank to the condensate system, the licensee collected a sample of the tank for lnalysis of total suspended solids (TSS) and total organic carbon (TDC).

These materials are sampled to ensure the liquid is of proper quality prior to recycling the liquid for reus The licensee compared the sample analysis results to the limits outlined in procedure HC.CH-E.ZZ-0012 (Q) - Revision 1 The results were TSS 500 parts per billion (ppb) versus an expected value of <100 ppb; and >250 ppb TOC versus a limit of

<100 pp This precluded the tank from being recycled for reus As a result, the licensee elected to reprocess the tank and resample its content After reprocessing the tank, the licensee again noted high TSS and high TD A decision was made to release the tank to the river since radioactivity concentrations of the the tank were expected to be low and there were no limits on TDC and TSS for effluent release The pH of the liquid to be discharged was neutra When the licensee analyzed the tank effluent for radioactivity concentrations,.the radioactivity was higher than expected and a decision was made not to release the tank in order to maintain offsite releases lo The original tank contents were processed by both

• the floor drain collector system and the waste collector syste The liquid was not able to meet either limits for recycling in accordance with procedures, nor acceptable radioactivity concentrations for release to the environmen As attempts were ongoing to cleanup the tank, the radwaste system continued to receive its daily normal input of about 20,000 gallons per da The ability of the radwaste system to process this input was adversely affected by two separate plant events, the main condenser 11A 11 water box repair of June 13, 1990 (see NRC Inspection Report 50-354/90-10) and the repair of the leak that had developed in the station service water system (see section 7.3 of this report).

The combination of these repair efforts resulted in a large amount of high salt content water being admitted to the liquid effluent radwaste system, and the salts in the water greatly reduced the efficiency of the resins in the liquid radwaste syste The licensee recognized that additional action must be taken to cleanup the liquid accumulating and initiated reviews to change the type of resins used in cleaning up the the liqui Numerous methods were proposed and reviewed during the week of June 18, 199 Late on June 20, 1990, the licensee estimated that there were 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br /> before radwaste tanks would start to overflo However, the tanks began to overflow only eight hours late On the morning of June 21, 1990, liquid was observed in the Waste Surge Tank Room, the A and B Floor Drain Collector Tank Room and the Detergent Drain Pump Room. The licensee estimated that between 70,000 and 100,000 gallons of liquid may have overflowed to the floo An Incident Report was issued on June 21, 1990, to document this radwaste overflo The licensee's review indicated no personnel were affected by the liquid in that no personnel contaminations had occurred and no airborne radioactivity intakes had occurred. The liquid was contained within tank room walls whose design precluded release of liquid and provided shieldin The licensee collected soil and water samples. around the station and no radionuclides attributable to the liquid spill were identifie The inspector concluded that the spill did not appear to have any signifi~ant impact onsite or off.site.

• *

During the period June 22-27, 1990, the licensee changed the resin overlay on the floor drain and waste filter This allowed the radioactivity concentrations to be successfully reduced to allow the liquid to be released in a controlled fashion consistent with Technical Specification requirements. At the time of this event and the end of this reporting period, the licensee was attempting to determine the cause of the unexpected high TOC and TSS concentrations. This matter will be reviewed during future inspection 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 These inspections were conducted in accordance with NRC inspection procedure 6270 Portions of the following activities were observed by the inspector:

Unit Salem 1 Salem 1 Hope Creek Hope Creek Hope Creek Hope Creek Work Request (WR)/Order (WO) or Procedure Description W0900715072 W0900719130 W0900619194 W0900705086 W0910122027 Troubleshooting procedure/activities Diesel generator fuel oil transfer pump 12 1SJ167 relief valve repair Service water pipe repair No. 2 turbine control valve repair C Residual heat removal pump motor oil change 40301 breaker

• 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 package The inspectors verified that the surveillance tests were performed in accordance with Technical Specifications, approved procedures, and NRC regulation These inspection activities were conducted in accordance with NRC inspection procedure 6172 The following surveillance test(s) was/were reviewed, with portions witnessed by the inspector:

Unit Procedure N Sa 1 e.m 1 SP(0)4.4.6.2D Salem 2 SP(0)4.4.7.2D Hope Creek HC. IC-FT. FD-001 Hope Creek HC.OP-ST.SF-003 Test Reactor coolant system le~k rate Reactor coolant system leak rate High pressure coolant injection high steam fl ow Reactor protection system manual scram test -,weekly With the exception of 4.3.1.A below, the surveillance testing activities inspected were effective with respect to meeting the safety objectives of the surveillance testing progra.3 Inspection Findings 4. Salem Reactor Coolant System Leak Rate Determination During this inspection, there were several occurrences of high reactor coolant system (RCS) leakage rates as measured during the Unit 1 and Unit 2 RCS water inventory balance surveillance procedur On June 5 and June 18, 1990, the Unit 1 RCS unidentified leakage rate was 1.078 gpm and 1.1 gpm, respectivel Unit 1

Technical Specification (TS) 3.4.6.2 and Unit 2 TS 3.4.7.2 specify that RCS unidentified leakage be limited to I.O gp The associated TS Action requirement specifies that the 1 eakage 'rate be reduced to within limits within four hour The licensee properly entered the appropriate TSs and complied with the Action requirements within the specified time perio The licensee was also attempting to identify sources of RCS leakage rates; RCS identified leakage is to be limited to IO.O gpm per TS requirement On June 22, I990, the Unit I RCS unidentified leakage again.exceeded I.O gpm (see A.I below).

On July I8, 1990, the inspector noted that Unit 1 safety injection accumulator water levels had been decreasing *and frequently refilled by unit operators (see A.2 below).

On July I9, I990, the Unit 2 RCS unidentified leakage rate was measured to be I.1 gp The appropriate action as required by-TSs were taken by the operators, specific.valve leakages were identified or isolated, and the surveillance was subsequently performed satisfactoril Leaking Boron Injection Tank Relief Valve The Unit 1 RCS unidentified leakage rate exceeded I.O gpm on June 22, I990 (1.06 gpm), and TSs were entered and followe The licensee then identified and quantified an RCS leakage source from a boron injection tank (BIT) outlet relief valve (ISJIO) by monitoring selected pipe temperatures and manipulating specific system valve The valve' is hard-piped to the waste holdup tan A flange downstream of lSJIO was removed and the leakage rate was measured to be 0.85 gpm. The flange was then replace The licensee measures RCS leakage by performing Unit 1 surveillance procedure SP(0)4.4.6.2D, 11 RCS

- Water Inventory Balance 11 ; SP(0)4.4.7.2D for Unit With parameters such as reactor power, RCS average temperature and pressurizer pressure stabilized, a three-hour RCS inventory balance (computer data collection) is performed, which measures and records gross RCS leakag Identified RCS leakage is than subtracted from total RCS leakage, from such sources as pressurizer relief tank (PRT) and reactor coolant drain tank (RCDT), to calculate the unidentified leakage rat TSs require that the RCS water

inventory balance be performed at least once per 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> The licensee normally performs this RCS leak rate surveillance once per da The licensee's procedure also allows the subtraction of RCS leakage outside containment, provided it was previously measured and documented on a separate data shee Such was the case for

the lSJlO relief valve leakag Leakage from that valve was not previously subtracted from the gross RCS leakage rate because leakage into the holdup tanks is not factored into the calculatio On July 17, 1990, the inspector determined that the 0.85 gpm RCS leakage from lSJlO, which was identified and quantified on June 22, 1990, was used in daily calculations without periodically reverifying its leakage rat The inspector expressed concern that a RCS leakage reduction from the 1SJ10 concurrent with the development of a different unidentified RCS leakage could possibly prevent recognition ~f the ne~

unidentified leakage until as much as 1:.85 gpm unidentified leakage rate is experience The inspector found that other leakage rates totaling about an additional 0.01 gpm are also carried on separate surveillance data sheet The 1icensee stated that a review of the leakage rate test procedure would be performe The acceptability of the practice of not periodically documenting and evaluating all RCS leakage rates is considered an unresolved item and will be reviewed during a subsequent inspection (UNR 50-272/90-19-03). Safety Injection Accumulator Leakage On July 18, 1990, during a review of operator log entries, the inspector noted that the safety injection (SI) accumulators were being refilled two to four times per day using the safety injection pump Unit operators and operations management personnel were questioned regarding the accumulator level reduction The licensee stated that they were aware of the issue and were investigating the apparent accumulator leakag The accumulators each discharge to one of the four RCS cold leg ECCS injection line The four SI system flow lines also discharge into the same ECCS injection line The SI system uses two pumps which form a common header that contains a

relief valve (SJ167) and a normally open and deactivated motor-operated isolation valve (SJ135)

before branching into the four SI flow lines to the cold leg Each of these four flow lines contains a check valve (SJ144).

Operations management directed a licensed senior reactor operator (SRO) to identify the leakage path from the accumulator On July 16, 1990, the SRO directed unit operators to electrically unblock and close SJ135, an action which rendered both SI trains inoperabl Operations management was consulted prior to performing that evolution and concurred with the activity, provided that an equipment operator (EO) was available should it become necessary to dispatch the EO to manually reopen the valv TS 3.0.3 was entered for the 31 minutes that SJ135 was closed and unblocke During that activity, the licensee concluded, by observation of accumulator and PRT levels, that the SJ167 was leaking into the PR At least one of the SJ144 check valves on the SI flow lines had to be leaking to allow flow into the PRT via the SJ16 Each of the RCS cold leg ECCS injection lines also contain a check valve (SJ56), downstream of all SI connecti-0ns and prior to RCS connectio It was also possible that some RCS leakage was going into the PRT, via leakage past the SJ56 and SJ144 check valves, then through the leaking relief valv When it was identified that at least some of the flow into the PRT was from the SI accumulators, the. licensee elected not to subtract PRT in-leakage from the measured gross RCS leakage during the leakage rate surveillance tes The inspector concluded that the decision was prudent since the SI accumulator leakage into the PRT was not RCS leakage, and taking credit for the PRT level increase (identified RCS) could potentially decrease the calculated RCS unidentified leakage rate.

• *

The licensee's system engineers were also involved with the troubleshooting activities relative to identifying and quantifying the leakage past SJ16 Since some of the leakage past the SJ167 could have been RCS leakage (past the SJ56s),

system engineering processed a procedure change so that the accumulator leakage rate could be quantified and subtracted from the PRT in-leakage rat This was successfully performed on July 21, 1990, when accumulator leakage was measured to be 0.77 gpm and corrected PRT in-leakage (RCS Identified) was calculated to be 0.26 gp Total unidentified leakage was 0.90 gp The licensee elected to replace the SJ167 relief valve while operating, an evolution that would require TS 3.0.3 entry due to again disabling both SI train On July 21, 1990, the NRC conducted a conference call with the licensee regarding their planned entry into TS 3.0.3 for the SJ167 valve repai On July 22, 1990, the licensee entered.TS 3. for a short duration to replace the SJ167 relief valv The planned entry into TS 3.0.3 was a management decision and the activity was planned and evaluated in advance and strictly controlle The inspector observed the activity, which lasted about 30 minutes and concluded that the evolution was properly controlled and coordinated, with good communication among the involved personne (See Section 8.1 for further discussion regarding the voluntary use of TS 3.0.3.)

Missed Surveillance Tests of Component Cooling Pumps On August 10, 1990, the licensee identified that two surveillance tests were missed on the Nos. 21 and 23 component cooling (CC) system pump The quarterly surveillance tests were last performed on May 6, 1990 and both were in the alert range as defined in ASME Section X When deviations fall within the alert range, the Code requires that the frequency of testings shall be double The licensee stated that the administrative process was initiated to implement the required actions, however, the documentation could not be foun Therefore, the next scheduled work order to perform the surveillance was the regularly scheduled August 8, 1990 date and the pumps were not tested on the increased interva The above is characterized as

• 4. *

missed surveillances required by Technical Specifications for which the licensee plans to subm*it a licensee event report (LER).

Planned corrective actions include enhancing the administrative process by which surveillance frequencies are increase Specifically, new requirements were instituted to maintain copies of the forms which initiate surveillance test frequency changes and to conduct weekly audits of the files to verify frequency change The inspector will review the LER and the associated corrective actions during a future inspectio There have been numerous examples of missed surveillances in the past at Sale However, none were specifically caused by the failure to temporarily increase test frequencie Accordingly, this licensee identified violation of Technical Specification surveillance requirements is not being cited because the criteria specified in Section V.G of the Enforcement Policy were satisfied (NON. 50-311/90-19-02).

Hope Creek A.. Missed Surveillance Test on the Control Room Ventilation System due to Personnel Error (LER 90-011)

During a review of completed surveillance procedures on July 3, 1990, the licensee determined that the scheduled monthly surveillance on the 118 11 control room emergency ventilation filtration (CREF) system had actually been run on the 11A 11 CREF trai The contra 1 room was informed and the nuclear shift supervisor (NSS) declared the 118 11 CREF train inoperabl The plant was in operational condition 1 (power operations)

with rea.ctor power at 100%.

The 118 11 CREF train monthly surveillance was subsequently performed satisfactoril A 24-hour non-emergency notification was made to the NRC as required by the licensee's Event Classification Guid The apparent cause of this event was personnel error on the part of the two NSS responsible for the completion of the 118 11 train surveillance in that the first NSS failed to ensure the correct train was tested (the work order for the test properly designated the 118 11 train)

while the second NSS failed to catch this error during his review of the completed surveillance test and its associated work order.

Licensee corrective actions for this recent missed surveillance included counseling of the NSSs involved and review of the event by all personnel during requalificatio~ trainin The inspector observed that while the performance of a surveillance on an incorrect train had apparently not occurred previously at the

station, inadequate reviews of completed surveillances were causal factors in two earlier events (LER 89-024 and LER 88-032).

The licensee identified violation is not being cited because the criteria specified in Section V.G of the Enforcement Policy were satisfied (NON 50-354/90-14-01). EMERGENCY PREPAREDNESS Inspection Activity The inspector reviewed PSE&G 1s conformance with 10CFR50.47 regarding implementation of the emergency plan and procedure In addition, licensee event notifications and reporting requirements per 10CFR50.72 and 73 were reviewe.2 Inspection Findings.

SECURITY Loss of ENS Phone On July 17, 1990, at about 10:30 a.m., both Hope Creek and Salem lost the ENS phone as well as other site phone system The cause of the ENS phone loss was due to underground digging in Salem Cit The ENS phone was restored later that da The licensee made notifications to the NRC as require.1 Inspection Activity PSE&G 1 s conformance with the security program was verified on a periodic basis, including the adequacy of staffing, entry control, alarm stations, and physical boundarie These inspection activities were conducted in accordance with NRC inspection procedure 7170.2 Inspection Findings Security Program Audits The inspector reviewed Quality Assurance (QA) audits No.88-026, 89-031 and 90-031 of the security progra Deficiencies and QA audit findings were documented, including corrective action The inspector concluded that the audits were thorough and well documente.

ENGINEERING/TECHNICAL SUPPORT 7.1 Overspeed Trip Devices For Terry Turbines Common On June 26, 1990, the inspector was informed of vendor correspondence by Dresser-Rand dated June 5, 1990 regarding overspeed trip tappet problems for Terry Stearn Turbine The auxiliary feedwater (AFW) system at Salem and the high pressure coolant tnjection (HPCI)

system at Hope Creek are potentially affecte The prob 1 em described by the vendor is a failure* of the overspeed trip tappet device to reset once trippe The original ball type tappet assembly was replaced by a molded head type tappet manufactured of polyurethan Under high temperature and humidity, the head can swell resulting in decreased clearance between the head and guid The vendor recornrnende.d a rnodificatio.n to either a pin or disc type tappet assembl The inspector confirmed that PSE&G received this letter and entered it into their action tracking syste The operating assessment group reviewed this information for Sa 1 em and Hope Creek applicabilit A 1 so, the group researched relevant industry information, including NRC information notice 88-67, General Electric SIL-392 and RICSIL-37, and INPO SOER 89-Discussions were held with reliability and assessment and operating assessment personne The inspector concluded that the licensee was proactive in their treatment *nd pursuit of this vendor informatio Salem The inspector reviewed the Salem AFW overspeed trip device desig Discussions were held with system engineers, and a review of related drawings and documentation was performe The Salem AFW overspeed trip device is a spring clip (disc) type tappet (Model number 1057 GS2N emergency linkage B/M 9030859).

The inspector concluded that the Salem AFW overspeed trip design is not the susceptible design described in the vendor lette The inspector noted the AFW system engineers to be responsive to NRC questioning and very knowledgeable of his system and design of the overspeed trip devic *

32 Hope Creek 7.2 Salem The inspector also reviewed the Hope Creek HPCI overspeed trip device desig Discussions were held with system and maintenance engineer A review of related drawings and documentation was conducte The HPCI overspeed trip device had been modified from the ball type tappet assembly to the molded head type during the previous refueling outage (Fall 1989).

Based on the receipt of this vendor information, the licensee is pursuing modifications for this overspeed trip tappet due to concerns expressed in the vendor lette Current plans are to perform the modification next refueling outage (December 1990).

The licensee concluded that continued operation was satisfactory because the problem being with the reset function only and no known failures at this tim The inspector concluded that the Hope Creek HPCI overspeed trip design is the susceptible design as described in the vendor lette The inspectpr also noted the Hope Creek system and maintenance engineers to be responsive to NRC questioning and very; knowledgeable of their system, and of the overspeed trip design problem and histor Limitorque Motor Pinion Key Failures The inspector reviewed a metallurgical report covering a number of motor pinion key failure The keys were used in the Limitorque valve actuators with Pratt and Jamesbury valves in the service water syste The keys in most cases were found to have fractured after being severely distorte The investigation concluded that the failures were due to the key material not being strong enough to withstand the applied load The failed keys were manufactured from mild carbon steel (AISI 1018) with Brinell hardness values ranging between 160-19 Alloy steel (AI93-B7) with Brinell hardness values of 294-301 was chosen as the replacement material. It's acceptability was verified by the licensee in 60 cyclic test The licensee indicated that the Limitorque actuators with new keys will be examined at the next refuelin The licensee issued a Part 21 on April 22,.1990 to cover the subject failur *

The inspector found no deficiencies in the licensee 1 s failure analysis report or his corrective action with regard to replacing the old keys with stronger material Part 21 Report on Westinghouse Series 7100 Systems On June 21, 1990, Westinghouse Electric Corporation notified the NRC via telephone of the existence of a potential substantial safety hazard in accordance with the requirements of lOCFR Part 2 A written report was subsequently submitted on June 22, 199 The issue concerned a potential lack of electrical isolation for certain bistable outputs of reactor protection systems (RPS) utilizing Foxboro and Westinghouse Series 7100 process instrumentation system Salem Units 1 and 2 utilize the Series 7100 syste The Westinghouse letter concluded that for extreme faults, fuse/breaker coordination could not be guaranteed and, therefore, the separate fusing to provide isolation capability to the analog bistables could not be wholly re 1 i ed upo If the RPS rack supply breaker trips first, the potential was determined to exist for all protection cabinets experiencing the fault to lose power, possibly deenergizing multiple protection cabinets and resulting in a reactor trip, but also potentially losing indication capabilities which may hamper operator response to the tri Westinghouse estimated the probability of the postulated sequence of events to be very low, and was aware of no incidents having occurred at any plant operating with susceptible systems in which electrical faults in the control, non-safety systems, have caused the loss of power of any single protection system channel set, much less multiple redundant channel set Westinghouse judged that potentially affected plants can continue to operate while plant specific conditions are evaluated and any required corrective actions can be implemented on a scheduled basi They also provided specific recommendations for licensees to pursue to address the concern The licensee was verbally notified by Westinghouse of the concern on June 20, 1990, and promptly initiated actions to evaluate plant specific condition An engineering evaluation was developed and reviewed by the Station Operations Review Committee (SORC) on June 22, 1990, * IEEE Standard 279-1971, to which Salem Units 1 and 2 is committed, states that no credible failure

at the output of* an isolation device shall prevent the associated protection system channel from meeting the minimum performance requirements specified in the design base Based on a review of the fuse and breaker characteristic curves, the licensee determined that for all credible maximum fault failures, fuse/breaker coordination was verified to be in tac Therefore, the Salem design would adequately perform the required isolation between protection and control channel circuit The licensee 1 s evaluation further recommended that they investigate the feasibility of either upgrading the qualification of the series 7100 model 118 signal comparator to a lE classification, replacing the comparator with a qualified device, or adding a qualified device in series with the comparato The inspector reviewed the licensee 1 s evaluation and attended the June 22, 1990 SORC meeti~ No deficiencies were identi-fie The licensee 1s actions. will be reviewed during a future inspectio C.. Turbine Building Transformer Failures During this inspection period, there were three catastrophic failures of non-safety related transformers located in turbine buildin On June 21, 1990, the Unit 1 lH 4160/480 volt transformer failed while the unit was operating at full powe There was no significant operational impact on the unit, however, the unit could have been adverselJ impacted if backup components had not automatically starte On June 28, 1990, the Unit 2 2F 4160/480 volt transformer failed with the unit operating at 75% powe The unit tripped following a loss of feedwater as a result losing the control/lubrication (C/L) oil pump for No. 21 steam generator feed pump (SGFP).

This trip is discussed in detail in NRC Inspection Repqrt No. 50-272 and 50-311/90-20 and in Section 2.2.l.A of this repor For the June 21, 1990 transformer failure, the C/L oil pump associated with each of the two SGFP~ were being supplied power from the lH transformer, however, the backup C/L oil pumps automatically started and prevented a SGFP tri A third transformer failure occurred on July 12, 1990 when the Unit 2 2H 4160/240 volt transformer faile The unit was in Mode 4, and no significant operational problems were experience j

- J

Another recent transformer failure occurred on May 11, 1990 (See NRC Inspection Report 50-272 and 50-311/90-13) when the Unit 2 2HL lighting transformer faile Therefore, in a two month period, there have been four catastrophic transformer failures, one resulting in a unit reactor tri The inspector reviewed operator response to the June 21, 1990 lH transformer failure and determined that unit operators adequately responded to the even The inspector reviewed the incident report associated with the even In the incident summary section of the report, only 11 lH 460 volt transformer failed 11 was written without further event descriptio Although the appropriate station personnel (Operations, Maintenance, Engineering) appeared to understand the event, the incident report (IR) lacked sufficient detailed informatio Nuclear Administrative Procedure No. NA-AP.ZZ-06, 11 IR and Reportable Event Program 11,

requires the licensee event report coordinator to determine whether a fcllowup investigation is require There was insufficient information in the IR to make such a decision.

. A similar catastrophic transformer failure, which occurred only one week later on Unit 2 (June 28, 1990)

resulted in a plant trip (see section 2.2.1.A) due to a slightly different plant respons Although the previous IR was not closed out, and the issue of numerous transformer failures was ultimately evaluated, the qua 1 i ty of *i:.he June 21, 1990 IR (incident summary)

was poor and was indicative of inattention to detai The Significant Event Response Team (SERT) which was formed to review the June 28, 1990 Unit 2 reactor trip was assigned to review the transformer failure concern The associated SERT report was issued on July 6, 199 Inspector review of the SERT report relative to the transformer problems concluded that the evaluation, including short and long term recommendations, was goo The report concluded that the root cause of the transformer failure was accelerated aging of the transformer insulation due to high operating temperatures and voltage A contributing factor was that the setpoint for the transformer cooling fans to automatically energize was too high (certain transformers had no permanently installed cooling fans).

Some of the short term corrective actions included:

(1) improve the turbine building ventilation by performing corrective maintenance, (2) reduce the control room transformer *

trouble alarm from 190 to 160 degrees F, and (3) develop a plan for shedding transformer loads in the event of a high tempera-ture alar Some long term corrective actions include:

(1)

establish transformer design lift criteria based upon operating history and actual operating environments, (2) establish a replacement schedule for each transformer, (3) install missing transformer cooling fans or add temporary spot cooling fans to transformers running hot, and (4) install and monitor local reading winding ammeters for transformers to monitor loadin Licensee followup and implementation of the corrective actions will be monitored by the ~nspector Unit 2 Intermediate Range Nuclear Instrumentation Trip Setpoints On June 23, 1990, during initial power ascension from the Unit 2 refueling outage, the licensee identified that the predicted, in-place trip setpoints for the two intermediate range neutron instrumentation system (NIS)

monitors were non conservativ Reactor thermal power was at approximately 10%.

Reactor Engineering personnel were in the process of evaluating the predicted setpoints when it was determined that intermediate range monitor (IRM) 25% reactor trip setpoints for IRM detectors N35 and N36 IRMs were at 44% and 38.6%, respectivel There values exceeded those allowed by plant Technical Specifications (TSs),

and since both IRMs were rendered inoperable, TS 3. was entere Both N35 and N36 were adjusted and the appropriate TS Action requirements were satisfie A unit shutdown was not initiated since TS 3.0.3 was exited before one hour had expire The predicted IRM setpoint calculation is based upon variables such as core geometry and control rod positio An assessment of the accuracy of the predicted setpoints cannot be made until reactor power is between 5 and 15 percen The licensee veri-fied that the calculations were performed in accordance with procedure No calculation errors were identifie The licensee plans to complete a review to determine whether improvements can be made to increase the accuracy and reliability of predicted value calculations of reactor powe The IRM reactor trip at 25% power provides reactor protection during startup, and is redundant to the four power range NIS channel The IRMs are not credited in accident analyses and the power range channels were

• confirmed to be operabl Additional review is required in this area to independently evaluate the licensee's IRM setpoint prediction methodology and this item is unresolved (UNR 50-272/90-19-05). Hope Creek Station Service Water Temporary Non-Code Pipe Repair On June 19, 1990, a small through-wall leak was found in the Hope Creek station service water system pipin The flaw was located in the 30 inch diameter service water line which supplies the non-safety related Reactor Auxiliary Cooling System (RACS) heat exchanger downstream of the Safety Auxiliary Cooling System (SCS)

heat exchanger isolation valve This section of piping is ASME code class 3 pipe used in a moderate energy system, and the licensee intended to perform a non-code temporary repair of the leak until a code repair could be performed during the next refueling outag In order to get the relief from the NRC required to perform the non-code repair, PSE&G followed the direction provided in the newly published NRC Generic Letter (GL) 90-05, 11 Guidance for Performing Temporary Non-Code Repair of ASME Code Class 1, 2 and 3 Piping.

The licensee performed the necessary non-destructive examinations and convened an engineering team to perform the leak evaluation required by GL 90-0 The team concluded that the pin-hole leak met the provisions of the GL, and PSE&G submitted the request for the non-code repair to the NRC Materials and Chemical Engineering Branc PSE&G/Hope Creek was the first licensee to request relief for a temporary non-code repair of ASME code class piping, and several telephone conference calls and request revisions were necessary before a repair plan for the pipe could be agre~d upon by NRC and PSE& The repair method consisted of a small rubber patch placed immediately over the point of seepage, covered by a 3/8 inch thick, 4 inch diameter carbon steel plate curved to match the service water pipe outside diamete The inner surface of the plate was coated with an epoxy sealant, and the plate and patch were held in place with a steel guard applied circumferentially on the pipe after the epoxy sealant set u The repair was performed on July 14, 199 * *

The resident inspector and a Region I Materials and Processes specialist inspector were kept apprised of the leak and all proposed licensee corrective action The resident inspector attended conference calls made by the licensee to NRC and reviewed all repair proposals submitted by PSE& The inspector found the licensee's response to the leak to be timely and conservative and the engineering evaluations and repair plans to be well prepare The resident inspector has examined the repair that was made and noted that the leak has successfully been stoppe The licensee has developed a work request to accomplish a code repair of the pipe to be done at the next outage of sufficient duratio (Also, see NRC Inspection 50-354/90-13 for additional information).

SAFETY ASSESSMENT/QUALITY VERIFICATION Use of Technical Specification 3. Introduction Technical Specification (TS) 3.0.3 establishes the shutdown Action requirements that must be implemented when a Limiting Condition for Operation (LCO) is not met and the condition is not specifically addressed by the associated Action requirement TS 3.0.3 states that when the LCO is not met, except as provided by the associated Action requirements, within one hour, action shall be initiated to place the unit in a mode in which the specification does not appl The intended purpose of TS 3.0.3 is to provide guidance on the time limits for an orderly shutdown when individual LCO or Action requirements in other specifications cannot be complied wit Normally voluntary entry into TS 3.0.3 as an operational convenience deliberately places the plant in a condition where important safety equipment cannot be relied on to mitigate the consequence of acciden Salem During this inspection period, with Unit 1 at full power, the licensee voluntarily entered TS 3.0.3 twic Once on July 16, 1990 in an attempt to identify a leaking safety injection system relief valve, and again on July 22, 1990 to repair the leaking valve identified on July 16, 199 On July 16,. 1990, with the concurrence of the operating engineer, the licensee closed a normally open and de-energized valve (SJ135)

at Unit 1, which rendered both intermediate head safety injection subsystems inoperable, to determine whether

an upstream relief valve (SJ167) was leakin The valve was subsequently restored and TS 3.0.3 was exited after 31 minute Prior to the activity, the licensee ensured that an equipment operator was available to manually open the valve, if necessar The valve does not receive an automatic open signal on a safety injection actuatio On July 20, 1990, licensee management decided to replace the leaking SJ167 while at power by again entering TS 3. The inspectors discussed the proposed activities with the licensee and expressed concerns relative to intentionally defeating redundant safety train This activity would have involved electrically defeating (tagging) the single downstream valve (SJ135) in the common header and the two parallel upstream normally open motor operated valves (11 and 12SJ134).

The inspectors met with licensee management to discuss the specific details, planning and contingencies relative to the proposed maintenance on July 20, 199 A conference call was held on July 21,1990 with the licensee and NRC regional a~d resident personnel to further discuss the TS 3.0.3 pl~nned entr The licensee stated that sufficient personnel would be directly involved so that the valve~ could be manually restored if necessary, pre-job briefings would be held, all materials would be pre-staged, expected job time was of short duration (less than 45-minutes),

and maintenance personnel were experienced with this type of valve maintenanc The licensee also stated that emergency operating procedures were reviewe The NRC questioned whether a power reduction from 100% was considere After an engineering evaluation, the licensee.concluded that a power reduction to 60% would be prudent for this activit The licensee entered TS 3.0.3 on July 22, 1990 at 9:09 The valve replacement was successfully completed and TS 3.0.3 was exited at 9:40 The inspector observed the evolution from the control room, and determined that operational checks of other ECCS subsystems were completed prior to TS 3.0.3 entry, shift briefings were satisfactorily conducted, and communication was goo No deficiencies were identifie The July 22, 1990 TS 3. 0. 3 pl a.nned entry was we 11 thought-out in advance and strictly controlled by management oversigh The inspectors concluded that alternative options were considered, including a unit shutdown, and the licensee was aware of the seriousness *

and sensitivity to voluntary entry of TS 3. Additionally, the licensee maintained good communication with the NRC for this activit On the contrary, for the TS 3.0.3 voluntary entry on July 16, 1990, it was not apparent that the same level of sensitivity and management involvement was applie It is recognized, however, that the one valve that was closed (SJ135) was not electrically disable Further, the NRC was not aware of the July 16, 1990 TS 3. voluntary entry prior to the activit This was discussed with licensee management, who stated that the senior resident inspector would be notified prior to any future voluntary TS 3.0.3 entrie Hope Creek On August 10, 1990, the inspector was informed of the licensee 1 s intention to enter TS 3.0.3 on Saturday August 11, 1990 to replace a safety related Rosemount transmitter (reactor level transmitter LT-N0800).

The licensee determined that based on a Justification for Continued Operation (JCO) prepared to address requirements of NRC Bulletin 90-01 (A-O-VAR-CEE-0296, Revision 1 ), an 1153 series Rosemount transmitter required replacement by no later than August 15, 199 Replacing the transmitter on the affected instrument rack could cause perturbations resulting in spurious reactor protection system (RPS) and engineered safeguard features (ESFs) signals from other transmitter Therefore, in order to perform the replacement at power without causing a spurious r~actor scram and ESF actuation, the licensee concluded that the entire instrument rack containing the affected transmitter would.be valved out during the replacemen The isolated transmitters affected an RPS channel and multiple ESF systems for one of four division The ESF systems included the automatic depressurization system (ADS), one loop of core spray and one loop of low pressure coolant injection (LPCI).

TS 3.0.3 entry was therefore required to replace the transmitter during power operatio The licensee concluded that this TS 3.0.3 entry was an appropriate course of actio Other possible alternatives that were evaluated and not chosen include:

• *

Defer the transmitter replacement until the next unit shutdow This option* is inconsistent with the provisions of NRC Bulletin 90-01 and the associated JC Shut down the unit to perform the replacemen Render only the affected transmitter channel inoperable, thereby imposing a high risk of reactor trip and ECCS actuatio The inspector discussed the planned entry with licensee operations and plant management personne The licensee presented their plan to replace reactor level transmitter LT-N080D to the inspector and regional managemen The inspector questioned the availability of redundant RPS and ESF instrument channel The licensee stated that redundant reactor scram functions for reactor level were availabl Also, tha licensee stated that a redundant channel for ADS, and redundant core spray and LPCI systems were available.; In addition, manual initiation of the affected ~quipment

. was available and reactor operator personnel would be briefed prior to the maintenance activity.

On August 11, 1990 at 9:05 a.m., instrument rack C811 level instruments were isolated and TS 3.0.3 was entere LT-N080D was isolated and removed from servic At 9:42 a.m. other C811 rack instruments were returned to service and TS 3.0.3 was exite LT-N080D was replaced with a new RosemoJnt transmitte The licensee again isolated rack C811 instruments, and entered TS 3.0.3 at 2:25 LT-N080D and the other C811 instruments were returned to service, and TS 3. was exited a second time at 3:22 The inspector reviewed the licensee 1 s replacement activities including licensing letter NLR-190408, the JCO, TS action statement log numbers 90-1139 and 1140, TSs for the affected systems and instruments, and control room operator log The inspector also discussed the activity with licensed operators and maintenance personne The inspector concluded that the TS 3.0.3 entries were well planned and implemented, with adequate supervisory oversigh Conclusion The inspectors concluded that additional communication with the licensee is necessary to discuss the use of TS 3.0.3, including with particular emphasis on voluntary entry and the associated expected licensee actions and J

• reportability of TS 3.0.3 entr NRC Generic Letter (GL) No. 87-09 provided guidance for TS modifications, including TS 3.0.3 basis section, which were expected to result in improved TS This GL provided specific gu-idance relative to voluntary removal of redundant safety system The licensee previously submitted a TS change request to implement related change Also, guidance should be included in administrative procedures to ensure TS 3.0.3 entries are strictly controlle The licensee stated that they would pursue changes to their administrative procedure Station Operations Review Committee (SORC)

The inspector attended a combined Salem and Hope Creek SORC Meeting on August 14, 199 Salem SORC meeting number 90-106 and Hope Creek SORC meeting number 90-73 approved three nuclear department administrative procedures (NA-AP):

NC.NA-AP.ZZ-OOOl(Q), Nuclear Department Procedure System NC.NA-AP.ZZ-0032(Q), Preparation, Review and Approval of Procedures NC.NA-AP.ZZ-0059(Q), lOCFRS0.59 Reviews and Safety Evaluations These procedures are common for both stations, and revise/replace the current Salem and Hope Creek administrative prJcedure This is part of the licensee's process to upgrade and consolidate their administrative programs and processe The inspector verified that the SORC meetings met the quorum requirements of Technical Specifications and was conducted per station procedure Each SORC (Hope Creek and Salem)

displayed a questioning attitude directed towards nuclear safet.

LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPORTS, AND OPEN ITEM FOLLOWUP LERs and Reports PSE&G submitted licensee event reports, and special and periodic reports, which were reviewed for accuracy and the adequacy of the evaluation.

• 43 Salem and Hope Creek Monthly Operating Reports for June and July 1990 No unacceptable conditions were note Salem Special Reports Unit 1 and 2 Special Reports 88-3-22 (June 6, 1990) and 88-3-23 (July 3, 1990) address additional fire barrier seal impairments identified by the license The inspector verified that hourly fire watches were initiated as require Unit 1 Special Report 90-2 (June 13, 1990) addresses inoperability of both fire pumps on June 1, 199 The number 1 pump was out of service for maintenance and a routine fire protection tour noted that the number 2 pump had an overspeed trip actuatio Licensee actions were in accordance with Technical Specification 3.7.1 Both fire pumps were returned to servic Unit 2 Special Report 90-4 (May 30, 1990) addresses steam generator tube plugging during the fifth refueling outag NRC Inspection 50-311/90-15 ~eviewed this issue.

Unit 2 Special Reports 90-6 and 90-7 (June 13, 1990) address diesel generator (DG) valid and non-valid failures as follows:

DG Number Date Valid/Non-Valid Cause 2A May 18, 1990 Valid Jacket water leak 2B May 21, 1990 Valid Jacket water leak 2B May 22, 1990 Non-Valid Personnel error These jacket water leaks were due to a loosened fitting (2A)

and a cracked nipple (2B).

Both appear to be vibration induced fatigu Similar failures were identified in May 1988 (18) and September 1989 (2B).

The remaining DGs were inspected, no additional problems were note Longer term corrective actions will be based on an in-process metallurgical analysi *

Unit 2 Special Report 90-8 (June 13, 1990) addresses the inoperability of the diesel generator (DG) Cardox system for longer than 14 day This outage of the Cardox was planned due to maintenance of the DG A fire watch was posted in the area until DG maintenance activities were completed and the Cardox system returned to servic Salem LERs Unit 1 LER 89-31 Revision 1 addresses a second event associated with high oxygen in the waste gas syste The licensee has initiated a dedicated team to review this issue, including extensive sampling and monitorin The unresolved item (272/89-15-08) remains open pending the completion of licensee actions and LER revisio LER 90-14 concerns the licensee identified safety injection flow rate inadequacies on Ap~il 9, 199 NRC Special Inspection 50-272/90-12 and 50-311/90-12 reviewe~ this even No inadequacies were noted relative to th~s LE LER 90-15 concerns a control room radiation monitor and ESF actuation that occurred on April 30, 199 event was reviewed in NRC Inspection *S0-272/90-1 inadequacies were noted relative to this LE failure The No LER 90-16 concerns a service water motor operated valve failures caused by shearing of the motor pinion gea This event was reviewed in N~C Inspection 50-272/90-11, including the licensee 1 s lOCFR Part 21 notificatio No inadequacies were noted relative to this LE LER 90-18 concerns a control room radiation monitor high spike that occurred on May 28, 199 No specific root cause was identified; however, further investigation is continuin No inadequacies were noted relative to this LE LER 90-19 concerns a main steamline isolation that occurred on June 3, 1990 in Mode 4 during reactor heatu The event was reviewed in NRC Inspection 50-272/90-1 The licensee believes the cause of this event to be related to main steamline flow instrumentation equipment concerns (unresolved item 272/88-17-01).

The licensee intends to continue to pursue design modifications as discussed in previous LER The inspector had no further questions at this time and the unresolved item remains ope (See section 2.2.1.E of this report).

. i

LER 90-20 concerns a licensee identified Technical Specification (TS) setpoint erro TS 3.3-1 requires that nuclear instrumentation permissive P-6 be reset at less than 6E-11 Amps intermediate rang However, surveillance procedures adjusted this reset valve to 5E-11 Amp The licensee 1 s TS Review Project personnel identified this deficienc The licensee revised the appropriate procedure This is a licensee identified violation and is not being cited because the criteria of Section V.G of the enforcement policy were satisfied (NON 50-272/90-19-04).

Unit 2 LERs 90-14 and 90-15 concern containment radiation monitor 2R12A channe 1 spikes on April 15 and 19, 199 The events were reviewed in NRC Inspection 50-311/90-1 No inadequacies were noted relative to these LER LERs 90-21, 90-22, 90-26 concern containment radiation monitor (2R12A and B) channel spikes on May 15, May 22 and June 9, 199 No inadequacies were noted re 1 at i ve to these LER LER 90-23 concerns a loss of maintenance on May 16, 199 Inspection 50-311/90-1 No relative to this LE the 2A vital bus during The event was reviewed in NRC inadequacies were noted LER 90-24 concerns an unmonitored liquid release on May 20-21, 199 The event was reviewed in NRC Inspections 50-311/90-13 and 9J-1 No inadequacies were noted relative to this LE LER 90-25 concerns lack of vent openings for the main steam vent valve control panels, thus affecting their environmental qualificatio The event was reviewed in NRC Inspection 50-311/90-13 and this item is unresolved pending NRC review (UNR 50-311/90-19-01).

LER 90-27 concerns a high range monitor plant ventilation (2R45C) spiked high causing a containment isolation signa The event was reviewed in section 2.2.1.C of this repor No inadequacies were noted relative to this LE LER 90-28 concerns non-conservative trip setpoints for nuclear instrument intermediate range channels during startup from Unit 2 fifth refueling outag (See section 7.2.D of this report.)

• LER 90-29 concerns a reactor trip on June 28, 1990 due to low steam generator level coincident with steam/feed flow mismatc (See section 2.2.1.A of this report.)

No inadequacies were noted relative to this LE LER 90-30 concerns a containment radiation monitor (2Rl2A)

actuation due to a personnel error by maintenance personnel during troubleshooting activitie The event was reviewed in section 2.2.1.C of this repor No inadequacies were noted relative to this LE Hope Creek LERs LER 90-008 concerns the miscalibration of a reactor building exhaust radiation monitor and the resultant Technical Specification violation which occurred on June 4, 199 This event, the licensee's actions and the NRC inspection of the event are described in NRC Inspection Report 50-354/90-1 This was a non cited violation described in that repor The inspector reviewed the LER and found no discrepancies in its form or conten LER 90-009 addressed the High Pressure Coolant Injection (HPCI) system being declared inoperable on June 7, 1990, due to high moisture and sediment contamination of the HPCI turbine lube oi This event was also previously described in NRC Inspection Report 50-354/90-1 The inspector reviewed the LER, noted the licensee's corrective action of planning the installation of a line at the low point in the HPCI lube oil reservoir, and found the LER to be acceptabl LER 90-010 is discussed LER 90-011 is. discussed Open Items The following previous during this inspection reference purpose Site Salem 272/88-17-01 272/89-15-08 in section 2.2.2.A of this repor in section 4.3.2.A of this repor inspection items were followed up and are tabulated below for cross Section.1 Status Open Open

• 1 MEETINGS 10.1 Resident 1 The inspectors met with Mr. V. J. Polizzi and Mr. J. Hagan 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 Region I review and discussions with PSE&G, it was determined that this report does not contain information subject to 10 CFR 2 restriction The inspector presented to the Hope Creek and Salem general managers a copy of a memo dated February 22, 1990 from Murley, Director, Office of Nuclear Reactor Regulation to the Regional Administrators on the subject of temporary waivers of complianc This memo includes a description of information NRC requires in a waiver of compliance reques Specialist Inspection Reporting Date(s)

Subject Report N Inspector 5/29-6/1/90 Radcon 272/90-16; Jang 311/90-16 6/25-7/6/90 Emergency 272/90-18; Amato Preparedness 311/90-18 6/18-6/22/90 Engi neeri ng/ISI 354/90-13 McBrearty 6/25-6/29/90 Radcon 354/90-15 Nimitz