IR 05000272/1990024

Insp Repts 50-272/90-24,50-311/90-24 & 50-354/90-20 on 901002-1112.No Violations Noted.Major Areas Inspected: Operations,Radiological Controls,Maint & Surveillance Testing,Emergency Preparedness,Security & LERs

ML18095A639
Person / Time
Site:	Salem, Hope Creek
Issue date:	12/05/1990
From:	Swetland P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML18095A638	List: IR 05000272/1990024 ML18095A637
References
50-272-90-24, 50-311-90-24, 50-354-90-20, NUDOCS 9012170113
Download: ML18095A639 (39)

Text

Report No License No Licensee:

Facilities:

Dates:

Inspectors:

Approved:

U. S. NUCLEAR REGULATORY COMMISSION 50-272/90-24 50-311/90-24 50-354/90-20 DPR-70 DPR-75 NPF-57

REGION I

Public Service Electric and Gas Company *

P. 0. Box 236 Hancocks Bridge, New Jersey 08038

. Salem Nuclear Generating Station Hope Creek Nuclear Generating Station October 2, 1990 - November 12, 1990 T. P. Johnson, Senior Resident Inspector S. M. Pindale, Resident Inspector

• S. T. Barr, Resident Inspecto H. K. Lathrop, Resident Inspector R. L. Nimitz, Senior Radiation Specialist

.D. G. Mann, Radiation Specialist H. I. Gregg, Senior Reactor Engineer A. E. Lopez, Reactor Engineer P. D~ Swetland, Chief, Projects Section 2A 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 four non-cited violations; three for Salem and one for Hope Creek.

ino12170113 901~0~

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' 05000272 PDR

SUMMARY *

Salem Inspection Reports 50-272/90-24; 50-311/90-24 Hope Creek Inspection Report 50-354/90-20

• October 2, 1990 - November 12, 1990 OPERATIONS (Modules 71707, 71710. 93702)

Salem: *The Salem units were operated in a safe manner.. Service water* leaks and* radiation monitoring system actuations were reported, and the licensee's actions were appropriate*. The auxiliary feedwater systems were adequately ali~ned:.

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• Hope Creek: The unit was operated in a saf~ manner. Operator response to an automatie reactor scram was good. Licensee followup to this scram was aggressive and thoroughly.

conducted.. Operators also adequately responded to a safety ~uXiliaries cooling system pumps trip and to an emergency fan start. The operability of the source range and intermediate range nuclear instruments dunng the March 27, 1990, startup is unreso~ved due to the * *

detector*connectors not being* environmentally qualified.

. RADIOLOGICAL CONTROLS (Modules 71707. 83729. 83750. 93702)

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Salem: Radiation hot spot tags do not include date and radiation level information. The improper setting of the containment fan coil unit.service water radiation monitors is unresolved~

• Hope Creek:.Review Of organization, staffing and qualification found no unacceptable conditions.. Several minor observations *of poor radiological controls. were noted. Licensee response to these items was* timely and appropriate.. Refueling outage preparations were.

determined to be proactive and goo MAINTENANCE/SURVEILLANCE (Modules 61726. 62703. 73756. 92701)

Salem: Licensee response to a Unit 1 safeguards equipment cabinet test failure was appropriate. Two non-cited licensee identified violations were noted.as follows: (1) reactor

• protection interlock functions were not fully tested; and, (2) a missed surveillance test for a*

service water pump occurre Hope Creek: An inadvertent core spray pump start occurred during testing due to an error by an I&C technician. A late surveillance local leak.rate test (by one day) on a drywell penetration is a licensee identified non~cited vio!atio *

EMERGENCY PREPAREDNESS <Mod~le 71707. 93702)

Lkensee preparations for a forecasted hurricane were proactive. A seismic event occurred near the site. However, it did not register on Salem/Hope Creek instrumentation as the magnitude was below the threshold. Followµp determined that the ~ope Creek active instrumentation was out of service due to lack of spare parts. A practice drill and the annual

• .emergency exercise were satisfactorily conducte *

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SECURITY (Module 71707. 93702)

No noteworthy findings were identified~

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ENGINEERING/TECHNICAL SuPPORT <Modules 71707)

Salerri: Out of service control room inst~mentation i.s being aggressively pursued by the

• licensee. *A concern regarding the new Unit2 Dixon indicators was unfounded. Failure to *

update theaxial flux difference setpoint is.a licensee identified violatio Hope Creek: Licensee engineers appropriately responded in evaluating a seismic even However, the inspector expressed concerns regarding the time that the active seismic monitoring system was out of service due to testing and equipment failur SAFETY ASSESSMENT/ASSURANCE OF QUALITY (Modules 30703. 71707. 9071. 92700. 92701. 92702. 94702)

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Salem: Licensee actions in response to Technical Specification (TS) 3.0.3 entries appear to be effectiv *

Hope Creek: Multiple TS 3.0.3 entries occurred due to Rosemount transmitter replacemen The environmental qualifica~ion for a replaced. transmitter is unresolved. *

General EmplOyee Training: The training was evaluated as being effective; however, improvements could be made in the.video tapes used ii

DETAILS* SUMMARY OF OPERATiONS Salem Units 1 and 2 Salem Units 1 and 2 began the report period operating at full power. *Minor power reductions occurred to perform maintenance and testing activities. On September 26, 1990, a Salem Unit. 1 shutdown was initiated.due to an inoperable safeguards equipment.control train (power reduced to 29 % ) * For the remainder of the inspection period power operation continued for both unit.2 Hope Creek The Hope Creek unit began the report period operating at full power. Small power reductions occurred to perform maintenance and testing.activities; The unit

automatically scrammed on November 4, 1990 when a* main steam isolation valve inadvertently closed at full power due to a rupture of the primary containment

• instrument gas line. The unit then,proceeded to cold shutdown and remained shutdown for the rest of the perio.0 OPERATIONS

• Inspection Activities *

The inspectors verified that the facilities were operated 'safely and in conformance with regulatory requirements. Public. Service Electric and Gas (PSE&G) Company

' management control was evaluated by direct observation of activities, tours of the facilities, interviews and discussions with personnel, independent verification of safety *

system status and Technical Specification Limiting Conditions for Operation, and review of facility records. These inspection activities were conducted in accordance

. with NRC inspection procedures 71707, 71110 and 93702. The inspectors performed normal and back shift inspections (612 hours0.00708 days <br />0.17 hours <br />0.00101 weeks <br />2.32866e-4 months <br />), including deep backshift inspection as follows: *

Unit Salem Hope Creek Inspection Hours 2:15 a.m. - 5:00 :30 a.m. - 12:00 noon 4:30 a.m. - 5:00 :00 a.m. - 10:30 a.m./

2:00 p.m. - 5:00 :00 a.m - 5:00 :00 a.m. - 10:30 a.mJ 2:00 p.m. - 5:00 Dates October 25, 1990 October 27, 1990 October 31, 1990 November 6, 1990 November 4, 1990 November 6, 1990

• 2 Inspection Findings.and Significant Plant Events* *

2.2.1 * Salem

. Service*Water (SW) System Leaks.

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• The licensee identified. SW system weld and piping leaks as follows:

Unit

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1

Component

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11 A 11 diesel generator cooler

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11B 11 diesel generator cooler.

"12A" component cooling

• heat exchanger folet. * *

Date/Time October 3, 1990/4:12 October 8, 1990/3:00 October 9, 1990/12:01 a.m.*

1121 11 residual heat October 19, 1990/1:45 removal system room cooler common discharge from

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11 13

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1114

, and "15

containment fan coil unit *. SW backup bearing h1brication line October* 23, 1990/12:45 October 24, 199011 :53 p.m~

• For each occurrence the leak was contained or isolated, an ENS call was made, the.

resident inspector was notified, an incident report was writteri to investigate the cause(s); and leak repair activities were initiated. *The inspector reviewed each occurrence; including licensee actions. 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 dutj.ng the period:

. Unit

Radiation Monitor Plant Ventilation (2R41)

Date/Time October 4, 1990/1:35 p.m. *

• Unit

2

1

Radiation Monitor Containment Noble Gas (lRllA)

Containment Iodine (2R12B)

Plant Ventilation

• (2R41C)

Con..tairiment Noble Gas (lRllA)

Containment Noble Gas (lRllA)

Date/Time October 5, 199011:06-October.29, 1990/1:21 October 30, 1990/2:24 November 1, 1990/6:45 November 12, 1990/6:42 The inspector reviewed licensee actions regarding these events.. The licensee intends*

to submit an LER for these events. No unacceptable conditions were :note. Previous Item Update (Closed) Unresolved Item 50-311/87-lS-03; power operations with a containment boundary that does not meet the analyzed design requirements for an indefinite period of time. *Due to both the inability to perform a timely val ye repair and lack of proper management attention, a manual valve was used for about one month while the qualified containment isolatfon valve (CIV) was inoperable. This action was in compliance with Technical. Specification (TS) requirements. Maintenance practices have been enhanced. such that the performance of the valve in question (2NT32) and the same Unit 1 valve (1NT32) has been more reliable. Additionally, the engineering department is pursuing a valve internals design change which will further increase valve reliabilit Increased management attention has been provided and demonstrated when TS -

• • Limiting Conditions for Operation (LCO} are entered at Salein so that prompt action 1s.

taken to exit the TSs~ The* station also administratively tracks TS LCOs and the * *

• Operations Department maintains a Priority List and a.Problem List to further ensure that safety concerns and LCOs are promptly evaluated..

Based upon the action taken by the maint~nance and engineering groups and the effective administrative controls in place for TS LCOs, this item is closed.

2.2.2 Hope Creek Intermediate Range Monitors CTRM) and Source Range Monitors CSRM) Operability On Oct()ber 12, 1990, during Station Operations Review Committee (SORC) revie,w of a justification for continued operation, the licensee determined that deficiencies regarding IRM/SRM environmental qualification (EQ) were reportable under Hope Creek Operating License eonditions 2.C and 2.F. The concern was identified during work order review of previous maintenance activities. Some IRM/SRM electrical *

connectors in the drywell may have been replaced using a type HN connector

• containing teflon (non-EQ) insulating material. The EQ program requires that connectors be made from Rexolite material.. This condition may have existed during the inost recent reactor startup on March 27, 1990.. *A 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> ENS call was made at 3:00 p.m. on October 12, 199 At the tim~ of the discovery, the unit was at 100% reactor power in the "run mode".

In this condition, the IRMs and SRMs are not required to be operabl However~ a number of IRMs and SRMs were documented as administratively inoperable due to multiple problems. The inspector confirmed this by reviewing the Technical Specification (TS) Action Statement log, control room indications, selected work

• orders and through discussions with Hcensee personne *

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Additional licensee followup, reviews, and troubleshooting determined* the following *

status as of October 15, 1990 (excluding the EQ concerns):

.Detector SRMA SRM SRMC SRMD IRMA IRMB IRMC IRMD IRME IRMF IRMG IRMH*

Status/Condition inoperable - failed detector functional functional marginal - noise problem functional inoperable.., noise problem functional functional functional inoperable - failed drive functional functional The inspector concluded that the licensee had adequate SRMs/IRMs to monitor reactor power during shutdown conditions. This was confirmed during the reactor scram that occurred on November 4, 1990. Three of four SRMs and six* of eight IRMs

responded fo neutron flux. The licensee initiated repair activities during the forced outage.period after the scra.

. LER 90-021 was :issued on November 9, i990. Teflon material (non-EQ) was found iri the following instrument detector connectors: SRMs A and* B; IRMs A, C, * D and F. These connectors were replaced with the correct EQ material.* The licensee concluded that the root cause was a discrepancy in the bill of material (BOM) as it was not updated in 1_988 when the vendor (GE) changed. the connector materia Also, the I&C supervisor failed to note this difference between the BOM and* the *

SRM/IRM repair procedure. Thus the wrong material was used in 1988-1989 time frame during IRM/SRM repair activities. *

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Technical Specification (l'S) Table 3.3.1-1 requires three operable IRMs per trip system and TS 3.3.7.6 requires three operable SRMs during operational condition 2 (reactor startup). During reactor startup on March 27, 1990, following the scra caused by a marsh fire; the licensee did not have these minimum required IRMs and SRMs in an* operable (EQ) conditio * The inspector also reviewed the status of the average power range monitor (APRM)

downscale reactor scram input. This condition coincident with a selected IRM upscale high or inoperable, *results in a reactors.cram in the "run mode". The inspector questioned licensee personnel regarding operability of this TS required scram functio The licensee stated that appropriate TS requirements (Tables 2. 2.1-1, 3. 3.1~1, 3. 3 ~ 1-2, and 4. 3.1.1-1) were met.. The licensee further stated that a recent TS change

requestdated September 4, 1990 (NLR-N90059/LCR 90-3) was submitted to the NRC to eliminate the APRM downscale trip requirement based on a vendor (General.

Electric) report. This TS change is under NRC revie The operability of the_SRMs and IRMs with respect to lOCFRS0.49 and conformance with TS Table 3..3.1-1 and TS 3.3.7.6 during the March 27, 1990, reactor startup is unresolved pending further licensee eval.l1ation and subsequent NRC *review (UNR 50-354/90-20-01).

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. Safety Auxiliaries Cooling System CSACS) Pump Trip (LER 90-017) *

On September 12, 1990, the "A 11 control room ventilation (CRV) chiller tripped, rendering the "A" CRV train inoperable. Since the "B" CRV train was undergoing scheduled maintenance, both trains were now inoperable and the unit entered the Technical Specification Action Statement 3.0.3 for several minutes. The initial investigation established that the "C" safety auxiliaries ci>oling system (SACS) pump supplying the 11A 11 loop of SACS had tripped.. The "A" loop of SACS had been supplying the cooling water to the "A" train of CRV and the loss of SACS flow resulted in a trip of the 11A" CRV chiller. Technicians had been collecting calibration and response data on the "C" delta pressure transmitter and as required by procedure,

• 6 had placed the test switch in "test" to block trip signals to the "C" SACS pump.

. *When the task was complete, the test switch was returned to its normal position and the. "C".SACS pump tripped due to the trip seq>oint on the associated delta pressure

• switch having drifted high, and this resulted in making up its trip contacts. Additional investigation revealed that this switch had not been calibrated since the plant started up in 1986. *There was no recumng preventive maintenance task for calibration for thi non-Teehnical Specification (TS) instrument. **

While the licensee was evaluating the SACS pump trip,_ a safety system functional review (SSFR) was started on SACS on September 17, 1990. * The team was composed of licensee and contract personnel. The SSFR was structured similar to the NRC' s safety system functional inspection (SSFI) and included a design review of system functional capabilities, reviews of operation, preventive and corrective maintenance and quality assurance, and inspeetion of system configuration and

• material conditio *

The liGensee's corrective actions included a review of all SACS instrumentation to assure that appropriate preventive maintenance recurring calibration work orders were in place.* The lack of recurring calibration work orders for some SACS _non-TS *

related instrumentation was highlighted as the top priority coneeni by the SACS SSFR team at their exit meeting on October 19, 1990. Similar calibration difficulties determined in two previous SSFRs led the team.to conclude that this concern could well apply to other safety-related systems.. The team's final report will be issued in late November 1990. The licensee's response to concerns raised in this report will be evaluated ill a future inspection report. The short-term actions taken to prevent recurrence of the SACS pump trip appeared to be adequate. No discrepancies wer noted in this LE * * *

• Filtration. Recirculation and Ventilation System (FRVS) Fan Start At about 4:20 p.m. on October 22, 1990, the control room was informed by a painting supervisor that the "E" FRVS system fan had started and was running. The operator ~erified that the "E" fan was running,* determined that there was no apparent

. reason for the fan to be in operation and stopped the fan after about five minutes of run time. Painting was being performed in a stairwell near the FRVS fans.** A temporary filter unit took suction on* the area to remove paint fumes before they could enter the reactor building. A specialist inspector noted, however, that the temporary ductwork had come loose from the filter unit so that unfiltered air was flowing into the reactor building near the FRVS fans. The licensee subsequently tested the "E" FRVS charcoal bed to determine if degradation had occurred from the exposure to the

. paint fumes as required by TS surveillance requirement 4.6.5.3.2.c. Results were satisfactory and the charcoal bed was declared operabl The spurious start of the "E" FRVS unit is similar to three other such_ starts.in the past three years. In two cases (see LERs90-006 and 87-016), the root cause(s) of the starts could not be.determined. In the third case (see LER 87~033), the cause was ascribed to dirty flow switch contacts. In response to the most recent prior event, some.of the flow _switches had their BUNA-N type diaphragms changed to a differen,t material. It was not clear in the October 22, 1990 event what had caused the "E" fan

• to start. The licensee's investigation_ was ongoing at the end of the report period, and

. the inspector had no further questions pending review of the licensee event repor Automatic Reaetor Scram At 12:42 a.m. on Sunday; November 4, 1990, *the unit scrammed from 100% power due-to a high avei:age power range monitor (APRM) signal generated as a result of a

. closure of the "B" inboard main steam isolation valve (MSIV). The cause of the MSIV closure was a rupture of a 1/4 inch stainless steel primary containment instrument gas (PCIG) line at the solenoid manifold block. The PCIG system*

provides motive force for a variety of safety-related air operated valves in the drywel Safety related equipment _responded as designed. All control rods inserted, Iio safety *

relief valves lifted and reactor water level was recovered by the reactor feed pump A second scrarri signal occurred while shutdown at 1:03 a.m. when reactor water level decreased below 12.5 inches during cooldown operations. The operating reactor feed puinp was placed In automatic to recover and control water level. An ENS call was made* to report these two reactor protection system actuations and the inspector was. *

informed at hom.

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• During followup operations when operators shifted the main condenser vacuum to the mechanical pump, a small noble gas radiation release occurred from the south plant

. vent (SPV). An existing fuel pin leak (NRC Inspection 50-354/90~16) exasperated this release. A meteorological temperature inversion existed at the site and. this resulted in SPV exhaust re-entering the turbine building causing abnormal radiation levels. The release was of short duration spikes which periodically alarmed the control room computer console (RM-11) SPV radiation monitor. Operators determined that this release was below the entry level of the emergency classification guide (ECG)* for the SPV because the duration was less than 15 minutes. * The licensee monitored and sampled building atmosphere and the SPV per their procedure Further followup determined the radiation release to be 59 % of TechniCal Specification instantaneous whole body noble gas lin;ii Concurrent with a cooldown to Mode 5 (Cold Shutdown), the licensee performed a survey of the drywell attempting to find the source of a 1. 7 gpm unidentified lea The leak was determined to be from-a through wall crack in a welded elbow on a one inch flow instrument line on the "B" reactor recirculation loop. This is the fifth occurrence of recirculation instrument line through wall cracks since the unit startup in

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inch. flow instrument lirie on the "B" reactor recirculation loop. This is the fifth occurrence of recirculation instrument line through wall cracks since the unit startup in mid-1986. Another ENS call was made to report this condition being outside the design basi *

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The licensee* performed followiip for the scram including a post scram review per procedure OP-AP.ZZ-lOl(Q) and a significant event response team (SERT) revie The Station Operating Review Committee approved the OP-Ai>.ZZ-101 review and authorized restart after completion of a number of items. These items and actions included:

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• Repairing the PCIG line to MSIV manifold block with a new design to minimize vibration,

Inspecting and modifying, as appropriate, the remaining MSIV PCIG lines, Repair of the reactor recirculation flow instrument line,

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Performance of non-destruc;:tive examination on the *other related instrument welds with no identified deficiencies, Installation of design changes 4EC-3186 and 3187 to bet.ter support these recirculation instrument lines and to provide monitoring of any low frequency vibration, and

Modification of the guidance in 'the ECG for radiation release Other previously identified. corrective and preventive mmnten~ce iteins *were.

peiformed. The SORC also required repair of some minor balance of plant equipment malfunctions that occurred, including: slow stroking of an instrument gas header valve, failure of the process computer, number 2 feedwater heater isoiation, and B secondary condensate pump trip. The SERT completed their review, briefed management and issued -a. final -report. Root cause of the scram was determined to be failure of ~e MSIV PCIG line due to fatigue caused by poor thread engagement and*

line vibration.* SERT*corrective actions and recommendations were also specified and complete **

The inspector responded to the site to review the scram and followup activities on November 4, 1990. The inspeetor monitored licensee actions to cool down the unit and to determine root cause of the scram. The inspector also reviewed the completed

QP-AP.ZZ-101, the SERT report, control room chart recorder traces, logs, sequence of events and alarm printouts, radiation monitor readings and release calculations, and other related documentation~. The oilshift reactor and senior reactor operators were interviewed. The inspector concluded that the.licensee had identified root cause and had adeqtiate corrective actions implemented or planned. Operator response to the scram was good. However, operators becarrie distracted With the instrument ga failure and plant cooldown, and this resulted in the second scram signal on low reactor level. The inspector also concluded that the licensee's normal line management's review and SERT review were timely, thorough and performed wel.3 Engineered Safety Feature (ESF) System Walkdown 2.3.1. Irispection Activity

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The inspeetors independently verified the operability of selected ESF systems by performing a walkdown of accessible portions of the system to confirm that system lineup procedures match* plant drawings and the as-built configuration. The ESF *

system walkdown was also ~onducted to identify equipment conditions that might degrade performance, to determine that instrumentation is calibrated and functioning, and to verify that valves are properly positioned and locked as appropriate. * This inspection was conducted in accordance with NRC inspection procedure 71710. *

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2.3.2 Inspection Findings Salem During the period November 2:.9, 1990, the inspector performed an ESF walkdown inspection of the Unit 1 and 2 auxiliary feedwater (AFW) systems. The inspector reviewed design drawings (electrical and piping), the updated FSAR, related technical specifications and surveillance tests, selected operatirig and maintenance procedures, and valve lineups. The inspector concluded that both the Unit 1 and 2 AFW systems

. were properly aligned for automatic initiatio *

Specific* equipment deficiencies were discussed with. licensee personnel. These items were previously identified by the licensee and scheduled for correction during upcoming refueling or system outages. The inspector noted that a temporary pressure device (Heise gauge) was installed in the Unit 1 No. 13 steam driven AFW pump recirculation line. This device was used for troubleshooting activities during October

• 1990. When questioned, the licensee removed the gauge and closed the sensing line

• valve. Further followup determined that this gauge had been identified during walkdown prior to a system outage, and tagged for removal. The inspector discussed this with licensee personnel and the inspector had no further questions at this tim *.

10 RADIOLOGICAL c'oNTROLS 3.1

. Inspection. Activities

. PSE&G' s conformance with the radiological protection program was. verified on a periodic basis. -These irispection activities were oonducted in accordance with NRC inspection procedures 71707, 83750 arid 9370.2 Inspection Findings and Review of Events 3.2.1 Salem Hot Spot Tags

. During a routine tour, the inspector noted that' radiation hot spot tags did not. include radiation levels or effective dates as currently implemented at Hope Creek. A check of the radiation protection (RP) proeedure (RP-204) revealed no requirement for this type information on hot spot tags. Discussions with RP management were held. The licensee* stated that they were currently reviewing this process for possible change Containment Fan Coil Unit Radiation Monitors Unit 1 LER 90-032 addresses the discovery by the licensee that the setpoints for the *

containment fan coil unit service water radiation monitor channels (1R13A and 1R13B) were not properly set. The root cause of the event was attributed to personnel *

error in that the correct setpoints for the two channels were not properly incorporated into the Offsite Dose Calculation Manual (ODCM) when scintillation crystals with a different sensitivity were replaced irl the two detectors during 1984.. *Corrective actions included proper setpoint adjustm~nt of the 1R13A and 1R13B monitors, a review of other radiation monitor calibration procedures to assure proper setpoints, and the tasking for the development of a new administrative procedure to assure the proper maint~nance of the ODCM. The inspector referred this LER for regional inspector revie This is unresolved pending review by a specialist inspector (UNR 50-272/90-24-01).

3.2.2 Hope Creek Organization/Staffing and Qualification The* specialist inspectors reviewed the organization and staffing. of the Hope Creek radiological controls (radiation protection}'-department. The inspectors also reviewed the qualifications of selected individuals within the organization.

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• • The inspectors reviewed the above matters with respect to the following:

Technical Specification 6.3, Unit Stiff Qualification Regulatory Guide 1.8 (1975), Personnel Selection and Training SA-AP-ZZ:-014(Q), Revision 3, Station.Personnel Qualification and Training

• Review of the qualifications of selected personnel found that properly qualified

• . personnel. were filling key positions. The new Radiation Protection Engli1eer was *.

found to meet the appropriate qualification requirements.. There has been. no significant staff turnover within the radiological controls. organization and excessive amounts of overtime are not used to complete routine radiation protection function The inspectors had no further questions at this' time." Inspector Tours of the Facility The specialist inspectors toured the Hope Creek facility during the course. of the inspection. The followin~ items were reviewed:

posting, barricading and _access control (as appropriate), to Radiation, and High Radi'!tion Areas, proper wearing of dosimetry by personnel, use of and adherence to the radiation work J>ermit, industrial safety practices, proper use of respiratory equipment, engineering controls *in lieu *of respiratory equipment, instaliatio11 of temporary shielding, use of portable arr monitoring equipment, proper use of _portal monitors,

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provision and use of radiation survey monitoring equipment and air sampling data, and proper use of anti-contamination clothin **.. The review was with respect to criteria contained in applicable station procedures and 10 CFR Part 2.

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Within the scope of this review, ilo violations were identified. The following observations were discussed with. the licerisee':s personnel:

At the filter diying and preparation tent on. the "unit 2 turbine deck", workers were preparing to enter a contaminated area wearing anti-contamination *

clothing improperly.. Ail individual's hood was improperly taped. As a result, an area of the workers neck was exposed. The inspectors discussed this with the Health Phy~ics Technician who immediately corrected the matter by re-taping the individual's hoo *

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Several i!ldividuals were seen improperly wearing dosimetry, i.e., the devices

• were not located in the same proximity on the chest. There is a sign at the access point stating that dosimetry devices are to be worn together. The licensee initiated a review of this matte.

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• Several places in the plant, hoses and electrical cords crossed into contaminated area*s without being properly secured. The hoses and cords could potentially.. *

be pulled from the contaminated areas.

Several station personnel were either not wearing safety glasses or wearing safety glasses without side shield *

When exiting the stafrwellon the 178 foot elevation, at approximately 3:00 *

• p.in. oil October 22, 1990, the exhaust hose for the HEPA unit used for stairwell ventilation during.painting, was disconnected. The inspectors pointed this out to the technician, who notified the painters, The painters secured the unit, reattached the hose, and re-established ventilation. Approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> later, there was an auto-start of the "E" FRVS fan. (See section 2.2.2.C.) The inspectors questioned Control Room operations personnel about the integrity of th~ FRVS charcoal beds after having potentially been exposed to paint fumes. The licensee's personnel indicated the potential for contamination of the charcoal bed would be evaluate Refueling Outage Preparation The Hope. Creek third refueling outage start date has been moved from January 19, 1991 to December 26, 1990. The 1990 station goal for maintaining radiatio exposure "as low as reasonably achievable" (ALARA) of less than 160 person-rem did not include any outage estimate. However, the goal should still be met since the* *

station has only expended 80% of the estimated dose for the year. The station

ALARA goal for 1990 was revised from 130 person-rem to_ 160 person-rem because of design changes during the yea The radiation protection (RP) department has completed approximately 42 % of the ALARA reviews for the outage. These reviews encompass approximately 60 % of the projected dose;.* This indicates good early involvement by the RP department in work activities plannin *

Following completion of the 1989 refueling outage, the station established a Cavity*

Decon Task Force. This task force reviewed the 1989 outage and established

• recommendations, for _the next outage, to reduce the potential for exposure and contamination from cavity wor *

• The licensee has contracted a vendor to perform the In-Service-Inspections (ISI). An unwritten policy of the vendor is to have vendor personnei enter the drywell in pairs.

. The station* ALARA committee has decided that for ALARA concerns, only 1 person will be permitted to e~ter the*drywell for ISI at a time. The remaining vendor

.personnel will monitor the evolution froi:n a remote viewing location outside the drywell. The two vendor personnel will be able to exchange responsibilities to prevent either one from receiving an inordinate amount of the total dose for the jo.

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The station plans to utilize. additional remote cameras, dose monitoring and communications systems to reduce the number of personnel undervessel and the collective drywell dose. For example, the licensee plans to have the Health Physics teehnician covering the undervessel work remotely monitor the undervessel wor The licensee intends to have the technician "dressed-out" and prepared to enter the drywell when neede The licensee also purchased a personal computer (PC) based shielding package. The

"Lead PC Piping Input Data Program" has been developed to the specifications of the station. This* package allows the ALARA group to. perform system and component calculations for various parameters. The program allows the licensee to assume an amount of lead shielding on a system or componentand determine the resultant dose rate. The program also performs.the engineering analysis for a 10 CFR 50.59, Safety Evaluation. The program also maintains a historical database and will perform a Cost/Benefit Analysis for ALARA considerations. This package is still under development to progressively input more system and component data into the database. This progressive development will allow expanded use with tim **

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. The licensee will.establish and staff an. appropriate radfological control organization to support outage wor.

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. The licensee will use robotics, mock-ups,* and appropriate personnel training to assist *

• in reducing the outage work.exposure. The following examples of robotics use and mock-up,s were identified:.

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.two underwater cleaning robots, two underwater surveillance vehicles, a semi-automatic control rod drive removal system, a semi-automatic control rod drive disassembly and cleaning machine, a recirculation pump mock-up, and

. a reactor water clean-up pump mock-u The inspectors concluded that licensee refueling outage preparations appear. to be proactive and very goo * 'MAINTENANCE/SURVEILLANCE TESTING Maintenance Inspection Activity The inspectors observed selected maintenance activities on safety-related equipment to

. ascertain whether" these activities were. conducted in accordance with. approved procedures, Technical Specifications, and*appropriate industrial codes and standard These inspeetions*were conducted in accordance with NRC inspection procedure

.62703:

Portions of the following activities were observed by the inspector:

Unit Salem 1 Work Request (WR)/

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Work Order (WO) or Procedure W0901028101 Description Replace "lB" Safeguards Equipment Control Chassis

Work Request (WR)/

Unit Salem 2 Work Order (WO) or Procedure W0901011167 Description

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Auxiliary Feedwater Valve Hope Creek IC.;GP.SE-003(Q),

IC::;-GP.SE~OlO(Q), -and W0901005149 through *

• W0901005160 Various WOs 22AF22 Repair

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Nuclea,r Illstrumentation repairs (intermediate and source range)

"C" Low Pressure Coolant Injection Mofor.

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

Specifications, approved procedures, and NRC regulations. These *inspection activities were conducted in accordance with NRC inspection procedure *61726. *

The following surveillance tests were reviewed, with portions witnessed by the inspector:

.uni Salem 1 Salem 2 Procedure No; S 1.MD-FT. SEC. 0002(Q)

• SP(0)4.0.5-P-Af<

(11, 12, J3)

PI/S~AF-3 *

SP(0)4.7. Hope Creek HC.IC-GP.ZZ-103 M9-ILP-03H Test

"lB" Safeguards Equipment Contr()l Logic Monthly Functional Test Auxiliary Feedwatet Pump Inservice Tests..

Auxiliary Feedwater Backleakage Auxiliary Feedwater System Valve Alignment

• Rosemount 1153 *Transmitter Neck Seal Pressure Test *

Local Leak Rate Test (penetration P-22)

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The surveillance testing activities inspected were effective with respect to meeting the safety objectives of the surveillance testing progra.3 Inspection Findings

• 4.3.1 * Salem * Initiation of Unit 1 Shutdown Due to Inoperable Equipment On October 26, 1990, auto-test circuit alarms* inadvertently annundated three times*on * *

the Unit 1 "lB" safeguards equipment control (SEC) train during s:urveillance testing activities.* The plant was operating at 100% power. The SEC is designed to start and load safety equipment onto.the vital electrical system under accident and/or blackout

. conditions.. No equipment was automatically started as a result of the auto-test alarm The "lB" SEC was declared inoperable at 8:57 a:m. for surveillance testing and tiJe appropriate Technical Specification {TS) Action Statement (No. 3.3.2.1) was entere Two hours are allowed for testing.. The required subsequent action is to place the unit*

in Mode 3 (Hot Standby). within six hours. Unit operators initiated a controlled shutdown at 10: 18 a;m., and properly reported the action to the NRC via the Emergency Notification System in accordance with. lOCFRS0.72 reporting

. requirement Technicians subsequently replaced. the suspect chassis* and satisfactorily tested the spare unit after installation. The "lB" SEC was restored at 2:21 p'lm. and was declared

. operable. The TS Action Statement was then exited and the power reduction was stopped at 29%. The unit was subsequently returned to full power operation. *

• J The inspecfor ob~erved the lieensee's troubleshooting and post-maintenance testing activities.* The inspector concluded that the activities were conducted in a well-controlled manner and the appropriate supervision and technical support personnel were involved with the activitie The licensee has experienced several operational problems and test failure associated with the SEC trains. The licensee's long term corrective action plan is to implement a modification which will upgrade major portions of the SEC cabinets. The licensee plans to send the suspect SEC chassis to the vendor (Vitro) for detailed troubleshooting and repair. The inspector will continue to monitor SEC system performance. The inspector had no further questions at this tim Licensee Identified Violations

• Unit 1 LER 90-024 concerns a licensee discovery that some of the reactor protection.

system interlock functions for the Units 1 and 2 P-10 and P-12 permissives were not

.* 17 fully tested in accordance with Technical Specification (TS) surveillance requirement The cause of the event was attributed to inadequate administrative control of the TS

.. surveillance testing program when the program was first initiated. Corrective actions included the issuance of new procedures to address testing of all required functions of the P-10 and P-12 permissives and the creation of a recurring task in the Salem computerized work* tracking system* to ensure completion of the surveillance test The tests were subsequently performed with satisfactory results. The inspector noted rio inadequacies relative to this LE This licensee identified violation is not being cited because the criteria sp~ified in Section V.G. of the Enforcement Policy were satisfied (NON 50:-272/90-24-02).

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• . Uni(2 LER 90-032 concerns a failure to comply with the inse~ice testing p~ogr~m per TS Surveillance 4.0.5. The testing frequency was not increased for one

component cooling (CC) water pump and one service water (SW) pump in the alert

• range.. The root cause was attributed to inadequate administrative controls,* with a contributing cause of the SW pump missed surveillance being personnel* error. *The licensee h.as.made interim* procedural modifications pending the results of a review of administrative controls and implementation of programmatic modifications. Retests:

were performed with satisfactory results. No inadequaeies were noted relative to this

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This licensee identified violation is not being cited because the criteria specified in Seetion V~G~ of the Enfo~cement Policy were satisfied (NON 50-311/90~24-0l).

4.3.2 Hope Cree Iriadvertent Core Spray Pump Start *

• On October 22, 1990 during the performance of surveillance procedure IC-CC.BE-0016(Q), "Channel E21A - K21A Pump Start Delay - Emergency Power", an inadvertent automatic signal started the "A" core spray pump. The K21A relay *

provides a six-second time dday for a pump start for load sequencing when powered

• from the emergency diesel generator. Under the supervision of a qualified technician,

. an I&C technician trainee was installing a temporary power supply to test the six-second delay function. As required by the procedure, an independent verifier "located

.. and labeled" the terminal to which the power supply lead was to be placed. The

• trainee then mistakenly placed the power supply lead to the wrong terminal. The indei)endent verifier did. not note the error. When the temporary power supply switch was closed, the K20A relay energized and started the pump. No actual.injection occurred as the injection valve low reactor pressure opening permissive was not satisfied. The pump was stopped immediately upon determining that the start was

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Licensee corrective actions included conducting a* meeting on October 31, 1990 with I&C supervisors and technicians at which the individuals involved reviewed their actions which led to the inadvertent pump start. A discussion of*the meaning of the *

phrase "locate and label" indicated that confusiOn existed on how verification of an action was to be accomplished since in this case the verification step preceded the landing of the power supply lead (effectively, there was no verification that the lead was landed on the correct terminal).. A number of methods to implement an adequate.

verification policy were discussed; however, no consensus was reache The inspector reviewed the incident report and lieeiisee actions taken to prevent recurrenee. The near term *actions (technician counseling, review of event with I&.C personnel) appear to be adequate. Long term corrective actions and* their effectiveness

• . and !he licensee event report will be reviewed in a future inspectio Environmental Qualification CEO) of Rosemount Model 1153 Transmitters The licensee has developed a surveillance procedure (HC.IC-GP.ZZ-103(Q)) to test the leak tightness of the EQ,neck seal between the sensor module and the electronics*

housing.. The inspector reviewed the procedure and witnessed the surveillance *

performed on, a suspect Model 1153 transmitter removed :from serVice three. weeks earlier. Based on the results of the surveillance, the licensee determined that this transmitter did have a failed (i.e., leaking) neck seal and was therefore not environmentally qualified. The licensee intends to perform this surveillance on a statistical sampling of 33 other Rosemount Model 1153 transmitters in vanous easy-to-access areas of the plant. The inspector concluded that the surveillance procedure appeared effective in demonstrating the adequacy of the neck seal and the maintenance *

of the transmitter's environmental qualificatio * Missed Surveillance Test CLER 90-019)

On. September 27; 1990, the inservice in~pection (ISi) supervisor notified the operating shift that a semi-annual Type "B" local leak rate test (LLRT) on the drywell personnel airlock was overdue.. The Technical Specifications (TSs) require a Type

"B" LLRT be performed on the airlock at least once per six months. The ci.irlock was previously tested on March 26, 1990; the test was scheduled for performance on September 26, 1990. Because 10CFR50, Appendix J inservice tests do not have the grace period allowances of TS 4.0.2, these tests are usually scheduled with a thirty day lead time. This was not done in this case and by the time the surveillance showed up on the daily overdue report, the performance interval had expired. As corrective

actions, the licensee administratively shortened the surveillance interval to five months, which would then provide a one month "grace period." Additionally, the TSs were reviewed to insure that all non-10CFR50, Appendix J surveillances were allowed the use of the TS 4.0.2 grace period. Licensee actions appeared adequate, however,.

the inspector noted the licensee's past history of missed surveillances and will continue

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to closely monitor licensee performance in this area. This licensee identified violation is not being cited because the criteria specified in Section V. G. * of the Enforcement Policy were satisfied (NON 50-354/90-20:.02).

. Previous Items Update *

(Closed) Vfolation (50-354/88-22-01); On May 27,* 1988, containment penetration P--

23 (drywell purge exhaust) failed its leak test. The line was to be isolated by removing the relay for valve GS-HV-4952. The adjacent relay for GS-liV-4958 was erroneously removed instead. The penetration was returned to service on May 30, *

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1988, but the erroneously removed relay was not reinstalled until discovered missing during routine valve stroke testing *on August 15, 1988. The licensee was cited for a violation of 10CFR50, Appendix B, Criterion XIV. The licensee's corrective actions included counselling of the personnel involved in the improper equipment safety tagging as well as training for all equipment operators and shift technicians on panel locations, configurations and labeling schemes. Similar training was given to all operations department shift personnel as part of the first cycle of requalification training. Operator aid placards showing relay location 'and relay contact orientation were placed on a number of safety significant cabinets. While specific documentation verifying that the appropriate traimng had been received could not be located, the inspector noted* thafno furthei"*similar tagging violations had occurred to date since this event took place and therefore concluded that the licensee's corrective actions had been successful in preventing recurrence. This item is closed.*

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(Closed) Unresolved Item (50-354/88-80-01); Time to Declare Component Inoperability. This inspection finding related to an inappropriate provision in procedure SA-AP.ZZ-027(Q), paragraph 5.4.7 of a 16 hour1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> allowance for data evaluation that was not in accordance with NRC's position to declare component inoperability as soon as tlie data are recognized as in the action rang.

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The inspector verified that the current procedure SA-AP.ZZ-02.7(Q), Revision 5, Station Inservice Inspection and Testing (IST) Program, was revised to clarify the startiiig point for declaration of component inoperability. The prior 16 hour1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> provision

• for data evaluation was removed from paragraph 5.4.7 and Attachment 1 of the procedure contains* clarification.of the starting point for declaring inoperability. This item is close.. (Closed) Unresolved Item (50-354/88-80-03); Modified Testable Check Valve. This inspection finding related to inappropriate procedural requirements arid training of equipment operators in the testing of these modified testable check valve The inspector reviewed IST procedures OP-IS.BC-103(Q), Revision 3 and OP'."IS.BC-104(Q), Revision 4.. The inspector verified that the.procedures were revised to incorporate the test methodology for the modified testable check valve exercise test *-

- The revised.procedures include highlighted information and guidance notes, more definitive provisions describing the disc movement with audible or alternative-verifications, and an equipment operator check off requirement for steps of the

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The inspector visited the trairiirig department and determined that a sample modified testable check _valve and visual aids were being utilized in the training of equipment *

operators arid -mechanics. The visual aids for the modified testable check valves were in process of being fu~er improved at the time of the inspector's revie In addition to review of the procedural upgrading and verification of training, the inspector witnessed the testing of valves 1AP-V046 on the "C" Residual Heat-Removal (RHR) system and 1AP-V058 on the "D" RHR system,. Testing of valve 1AP-V046 was performed on three occasions by three different equipment operators because handle movement in the neutral position required more force than valve 1AP-V058. The shift supervisor was contacted and he stated that the "C" RHR loop was

• out of service and that a normally_ closed valve downstream of valve 1AP-V046 was open and because of keep-fill flow, hydraulic problems could be the cause of stiff handle operation. The inspector contacted the_ QA department and requested that _the QA engineer who witnessed the test of valve 1AP-V046 verify that the retest was

_ satisfactory when the "C" loop was in normal configuration..

QA did witness the retest after RHR was rehirned to normal service. The conclusion

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was that the valve was easier to operate than the earlier testjng when the system was in the non-normal configuration. The_ equipment operator determined the valve was satisfactory-and commented the valve was slightly stiff to turn due to packing. The QA engineer documented details of the retest in Report SR-90-0423. This item is close (Closed) Violation (50-354/88-80-04); Design Control of Modified Testable Check Valves: The_ design change package for the modification to the Anchor.:Darling testable check valves did not include material evaluation of new internal_ parts, detailed assembly instructions, and final drawings of the modified valves. This finding resulted in. a violatio The inspector reviewed the licensee's corrective actions and verified that the design change package for the modified testable check valve was revised to include -

acceptability of materials, description for positioning the cam relative to the hinge ear contact point, staking considerations for the cam set screw, and exercising the valve to assure non binding. The inspector 3.1.so verified that the vendor drawings have been revised to reflect the modified and new parts. This item is close.

-(Open) Unresolved Item (50-354/88-80-02); Substantiation of Design and Seismic Capability of Weight Arrangements on Core Spray Pumps "B" and "D". At the time

of.NRC inspeetion 50-354/88-80, insufficient documentation was available for the inspector to verify design and seismic capability of the two different weight modifications. The following updates the status 9f this itei The inspector discussed this item with the licensing engineer, the system engineer and the General Electric site* representative and determined that this item. had not been * * * *

acted on. The licensing action tracking system records listed this item as issued on February 9, 1989, with a response due April 25, 1989, that was not met. A request dated June 14, 1990, asked for an ex~nsion to September 1, 1990, which agfiln was not met. * Further review by the inspector determined that the action tracking system did* not identify the missed response dates and activity to close the item was not Initiate *

This matter was discussed with the General Manager-Hope Creek Operations (GM-.

HCO) during a mini-exit meeting held by the inspector on October 19, 1990. The

• GM-HCO verbally committed to resolVe this itein by December 15, 199.0 EMERGENCY PREPAREDNESS 5.1 Inspection Activity The inspector reviewed PSE&G's conformance with 1QCFR50.47 regarding implementation of tqe emergency plan and procedures. 'In addition, licensee event notifications and reporting requirements pet 10CFR50.72 and 73 were reviewe.2 Inspection Findings Emergency Drill The Hope Creek facility conducted an emergency drill on October 9, 1990. The

.inspector observed portions of the drill from the Technical Support Center.. Licensee.

. pefformance was good and no unacceptable conditions were observe Annual Emergency Exercise The annual Artificial Island Emergency Plan exercise was conducted-on October 30, 1990.. This was a full-participation, FEMA Region Ill observed, ingestion pathway exercise for the state of Delaware. The Hope Creek Generating Station, including the use of the control room simulator, was evaluated. A team of five NRC inspectors evaluated the licensee's emergency preparedness-performance. Inspection findings are delineated in NRC Reports 50-354/90-80, 50-272/90-80 and 50-31 l/90-8 *

22 Hurricane Preparations A hurrican~ watch was issued for the nearby coastal areas during the period October

• • 12-14, 1990. The site was forecast for high wind and tidal conditions. The licensee

. made preparations at both Salem and Hope Creek stations for this foreCa.sted condition including:

Reviewing Emergency Classification Guides (ECGs),

Implementing* abnormal procedures,

. Inspecting the site and all outside areas for non-secure items, Briefing affected personnel on required actions,

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Verifying* operability of offsite and emergency power sources, and watertight doors and structures, and Ensuring availability of diesel fuel oi The inspectors reviewed the associated procedures and ECGs, verified licensee actions, and made plans for site coverage. * The inspectors concluded that the licensee was proactive in their approach to hurricane preparations. No unacceptable conditions were identified..

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Seismic Event at Salem/Hope Creek At 9:35 p.m. on October 23, 1990;Jan earthquake occurred with its epicenter located northeast of the site. The earthquake was heard and felt by station personnel. at both the Salem and Hope Creek facilities. The installed active seismic instrumentation at Salem did not record any seismic activity. Hope Creek's similar instrumentation was

• out of service due to surveillance test failures and unavailability of spare parts. The.

passive instrumentation (scratch plates) was functioning at both stations and no seismic *

event was recorded. Salem Units 1 & 2 and Hope Creek were all operating at full power at the time of the event. The licensee contacted the U.S. Earthquake Center in Denver, Colorado, and verified that an earthquake had occurred; The epicenter was latitude 39.5 degrees north and longitude 75.3 degrees west (about 12 miles from the *

site) and measured 3.2 on the Richter Scale. No Emergency Classification thresholds*

were exceeded. The* licensee dispatched operators to walkdown safety related and balance of plant systems to ensure system integrity. All systems were determined to be norma *

The licensee conducted further investigation with their seismic instrumentation setpoints and operation. The licensee concluded that the seismic activity should not

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-have been sensei nor recorded. This instrumentation is set to record a seismic -event at 0.02g acceleration or art equivalent 4.5 on the Richter Scal The inspectors monitored licensee activities regarding the_ earthquake and seismic

_ instrumentation performance~ Additional followup regarding instrumentation will be

performed and documented in a future report. (Aiso see section 7.2.A.)

6.0 - SECURITY 6.1-Inspectio~ Activity PSE&G's conformance with the security program was verlfied on a periodic basis, -

including the adequacy of staffing, entry control, alarm stations, -and physical boundaries. These inspection activities were conducted in accordance with NRC

- _i_nsJ)ection procedure 7170 ;2-

- Inspection Findings No noteworthy findings were identifie. 0 ENGINEERING/TECHNICAL SUPPORT Nuclear Service Water (SW) Header Pressure

_ During a routine Unit 2 coritrol room tour, the-inspector was informed by a licensed operator of out of setviee SW pressure instruments PA 5373 and PA 5386. These instruments provide header pressure indication for nuclear SW headers 21 and 22. -

The inspector verified that these indicators were being tracked out of service in -control room log 13 even-though pressure indication was available and indicating normal. A

- backup pressure recorder (PA 6312) and low pressure alarms. were also availabl The inspector noted that these indicators (PA 5373 and 5386) have been out of service since July 198 The inspector discussed this item with the system engineer who stated that the

_ indicators_ were not responding to SW system pressure changes. -The apparent cause-was faulty pressure transmitters which the licensee had determined to be obsolete. A design change package (DCP) had been initiated; however, it was low on the DCP priority list. The inspector confirmed this with licensee management personnel. The inspector expressed concern due to the importance of nuclear SW pressure indication and-the use of these instruments as ari entry condition for abnormal operating procedure AOP-SW-1, "Service Water Nuclear Header Leak." *

Further licensee review of out of service oontrol room indications (alarms,

• instruments, etc.) has concluded that the SW header pressure DCP should be accelerated. The inspector reviewed licensee actions regarding improving control room indications. These include:

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Assignment of a maintenance engineer to track progress. *

Tracking out of service instruments on the daily management.packag Management periodic review of progres The inspector will continue to review this item in future inspection Unit 2 Control Room Instrumentation In July 1990, *the NRC resident inspector staff reviewed a concern regarding. the analog instruments in the Salem Unit 2 control room that were replaced with digital indicators during the April-May 1990 Unit 2 refueling outage. The concern was that

~everru of the* analog instruments were found in a failed stat The inspectors interviewed Se\\feral members of different Salem control room operating crews iil order to determine.their ability to identify a failed indicator. *All operators were aware of the indications of a failed instrument and stated that the operability of

• indicators is an item* that is checked during control room board walk-downs. No *

operator recalled any of the Unit 2 control room instruments indicating failed prior to the refueling outag The inspectors also inter\\riewed two contractors who were the coordinators of the indicator replacement program. Both men were involved iri the tag out preparation and execution and with the specific instrumentation removal and replacemen Interviewed separately, both individuals stated that they never encountered a disabled or failed instrument in the course of their work. One of the contractors did suggest, however, that since some of.the instruments were replaced energized and some de-energized, it might have appeared to an observer that some of the instruments were

. found faile Other than the contractor's suggestion, the inspectors found no basis for this concern, and no unacceptable conditions were identifie Missed Axial Flux Difference Semoint Calibration LER 90-021 concerns a Technical Specification non-compliance in which the axial flux difference target flux band setpoint was not updated within the required time frame. The root cause of the event was attributed to personnel error in that the

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i~volved engineer did not initiate a work request to update the setpoints due to* his

. Il!isunderstatidmg of the applicable procedure. Licensee corrective actions included reviewing the eve1't with Reactor Engineerfug personnel and revising the procedure to

.*more clearly delinea:te engineering personnel responsibilities. The inspector reviewed

'the revised procedure, found the revision to be satisfactory, and noted.no inadequacies relative to this LE This licensee identified violation is not being cited because the criteria specified in Section V.G. of the Enforcement Policy were satisfied (NON 50-272/90-24-03).

Previous Item Update (Closed) Unresolved Item 272/88-17-01; main steam line flow (SLF)indication drif. The-licensee performed engineering evaluations and implemented several actions to

. address repeated drifting of the Unit 1 control room SLF indications. A meeting was he!d in the NRC Region I office to discuss these concerns on May 15, 1989. The Unit 1 and 2 steam flow taps (eight per unit) are different in that drain ports at the venturi are provided in Unit 2. A design change package (DCP) is currently planned to be implemented at Unit 1 during the upcoming winter refueling outage. The DCP is expected to eliminate condensation buildup that contributes to the dri_fting phenomenon. Unit 2 has not experienced the drifting proble *

. The licensee's short-terni corrective actions include blowdown of the instrument lines during* startup, obtaining steam flow data at several power plateaus during power ascension; implementing a conservative calibration following a unit shutdown and monitoring steam flow parameters on a weekly basis until the drift problem.has been resolve *

The licensee's actions thus far appear to have been effective in minimizing the number of related problems. The inspector reviewed the licensee's actions and interviewed system engineering and Operations personnel concerning the drift problem. No deficiencies were identified. The effectiveness of the steam flow instrument tap

. modification will be evaluated, by the inspector, dunng a future inspection. This item is close Hope Creek Seismic Instrumentation At Hope Creek the instrumentation in the seismic monitoring. panel (10C673) had been

_out of service since September 28, 1990, for a scheduled surveillance (and subsequ~nt repair). Consequently, the instrumentation was not available to record any seismic data from the October 23, 1990 earthquake.* The licensee removed and evaluated 48 scratch plates from the accessible monitors upon which would be recorded the

• maximum amplitude for each axis (north-south,* east-west and vertical). The majority of the plates indicated no diseernable motion had occurred. However, four plates had indications of ground motion in excess of l.3g. Since the National Earthquake Center in Colorado had stated that the. earthquake's maximum aceeleration was 0.003g ( on the Richter Scale), the licensee concluded that the readings in these. four plates

. were not credible. Following a forced shutdown and drywell de~inerting on *

November 4, 1990, the scratch plates for the monitors in the drywell (one on the core spray piping near its reactOr vessel penetration and a second on the reactor support -

. lateral truss) were removed and evaluated. These plates likewise indicated no *

. discernable motion.' *

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The inspector concluded that the licensee~s confirmatory actions were appropriate..

However, a concern* was noted related to the length of time (two weeks) apparently required to perform *a calibration. surveillance on the monitoring equipment in the

• upper control equipment room (panel 10C673) which rendered the monitors

. inoperable. In this case~ the-monitor was returned to service on October 26, 1990,.

two days prior to the expiration of the Technical Specification action statemen Station technical department personnel indicated that the surveillance duration issue would be assessed. with respect to reducing the time the seismic monitor would be out *

of service for. testing. Licensee actions*in this regard will be reviewed iri a future inspection report. The inspector had no further questions at this time. _ * SAFETY ASSESSMENT/QUALITY VERIFICATION Salem Technical Specification ITS) 3.0.3 Entry (Glosed) Violation 50-272/89-27-02; failure to initiate unit shutdowns after one hour when in TS 3.0.3 on two occasions (November 9 and 17, 1989). The licensee responded to the violation in a letter dated February 8; 1990. Corrective actions included revising the TS interpretation and obtaining approval by. the Station *

Operations Review Committee, informing operations personnel of management's expectations and including TS 3.0.3 actions iri licensed operator training program The inspector reviewed the response letter, verified corrective actions and interviewed selected operations personnel regarding TS 3.0.3 actions. The inspector noted that recent TS. 3.0.3 entries were adequately bandied as discussed in previous NRC resident inspection reports. Based on_ the above, the violation_ is considered close *

27 Hope Creek Technical Specification (TS) 3.0.3 Entr_y

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In followup to NRC Bulletin 90-01 on Rosemount Model 1153 µansmitters, the licensee identified a potential degraded pressure transmitter (1BE-N090N). This transmitter provides the core spray loop injection valve with an open permissive for reactor pressure. A spectrum analysis (frequency response) Identified that the transmitter was degrading due to oil loss. (e.g., the transmitter was not seeing any noise). The transmitter was declared inoperable at noon on_ October 3, 1990, and the TS action statements (TSASs) for core spray were entered:

The licensee made plans to replace the transmitter and developed a troubleshootin procedure per RC.IC-GP.ZZ-008(Q). In order to perform repairs, the licensee

. elected to isolate all instruments on the affected rack. This condition would put the licensee into TS 3.0.3 beeause the high pressure cooJant injection (HPCI) system would be inoperable due_to unavailability of one reactor.high level trip input. The licensee notified the resident inspector of their intentions. _

The inspector reviewed the troubleshooting procedure, electrical and logic drawings, and discussed the plan with licensee personnel. The plan required two TS 3. entries: one entry to isofate the transmitter and another during return to service. *

Recent revisions to procedure HC.OP-AP.ZZ-0002(Q), Revision 9, addressed voluntary TS 3.0.3 entries. The inspector reviewed the procedure and.determined it

• to be adequate; The troubleshooting plan was adequate; however, it lacked*

inforination informing operators whether HPCI would automatically st.art and would trip on high level. The inspector verified that the onshift operations personnel were

• knowledgeable of the plan and were aware of HPCI system statu During the evening; the licensee entered and exited TS 3.0.3 within the one hour time

__ limit during transmitter replacement. The following morning (October 4, 1990) senior maintenance supervision debriefed the techriician who performed the transmitter replacement. The technician questioned the existence of a foose jam nut located.

between the transmitter sensing head (mechanical) and cell (electrical). Visual

.. inspection confirmed this condition, and at H: 15 a.m. the licensee declared the replaced transmitter inoperable and entered the appropriate TSAS. Incident report 90-.

129 was written addressing this environmental qualification (EQ) concern for the transmitte A second troubleshooting plan was developed, TS 3.0.3 was again entered twice, and the transmitter was replaced with a new one from spares. This was completed during th~ evening hours on October 4, 1990.

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Further licensee review noted that the loose jam nut *had a required torque value of 35,

. foot-pounds. However, licensee procedures did not verify this torque value prior to

.* installation. * A test to check the pressure tightness of the transmitter and its EQ status *

was dev~loped in conjunction with the vendor. The licensee proposed to test this

transmitter and other selected ones installed in the plarit. LER 90-20, dated November 1, 1990, also addresses this item. This item is unresolved pending determination of transmitter operability, how the* jam nut became loosened, 10 CPR part 21 reportability and generic concerns review (UNR 50-354/90-20~03).

Control of Jumpers and Temporary Modifications (Closed) _Violation 50-354/89-02-01; temporary jumpers installed in the drywell equipment drain puI11ps without management knowledge. * The licensee responded to the violation in a letter dated April 28, 1989. The licensee attributed root cause to

• personnel error in failing to comply with procedure SA-AP.ZZ:-013, "Control of Temporary Modifications." Corrective actions included immediate removal of the jumpers, review of the incident with personnel involved, enhancements to the *

troubleshooting procedure and to SA-AP.ZZ-013, and retraining for operations,.

maintenance and technical department personne The inspector reviewed the licensee's response including corrective actions to prevent*

. recurrence. Recent reviews of troubleshooting activities and temporary modifications have revealed no similar problems. Based on the licensee's response and* inspector review, this violation.is close General Employee' Training (GET)

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• The inspector attended the Public Setvice GET requalificatfon program on October 23 and 24, 1990. The training included security, safety, radiation worker, emergency planning, quality assurance and employee quality/safety concern program, heat stress, hazardous materials, and fitness for dut *. The inspector concluded that the training was effective in providing the employee wit the necessary information. However, some improvement could be made in the video

. tapes that were used. For example, the security tape had a few minor errors and several of the tapes were out dated. The inspector discussed these items with licensee.

personnel in charge. of GET and their management. The licensee stated. that these shortcomings were previously recognized and that actions were in progress to upgrade the video tapes. The inspector had no further questions at this time. The effectiveness of GET will continue to be reviewed in future inspections.

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. LICENSEE.EVENT REPORTS (LER). PERIODIC AND SPECIAL REPORTS..

AND OPEN-ITEM FOLLOWUP 9.1 LERs and Reports

_PSE&G submitted the following licensee event reports and, special and periodic rep0rts; which were reviewed-for accuracy and the adequacy of the evaluation:

A;.

s*alem and Hope Creek Monthly Operating Reports for October 1990 No noteworthy findings. were identifiecl. _ Salem Special_ Reports Unit 1 Special Report No. 90-4 (August 7, 1990) discusses the improper operation of the DB-50 circuit breaker secondary contacts which occurred on June 12, 1990. This report _was submitted to the NRC for information only (i.e. not a required report per IOCFR Parts 21 or 50), and the event was discussed in NRC Inspection Report No.

.. 50-311/90~1.

Unit 2 Special Report No. 90-9 (August 15, 1990) describes a valid test failure '

' involving the 2A Emergency Diesel Generator. * The test failure was attributed to the failure of the diesel engine electro-hydraulic. governor actuator, which was subsequently replaced, allowing the successful completion of the required Technical

~pecification surveillance test. _ Additional licensee corrective actions are pending based on the results of the-failure analysis of this governor actuator and two others

-- which had similarly failed recently. *

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Unit 2 Special Report 90-10 (August 20, 1990) describes the inoperability of the automatic actuation capability of the 64. ft. and 84 ft. elevation Switchgear Rooms C02 Fire Protection Systems for greater than 14 days, which requires the submission of a report to the. NRC pet the Salem Technical Specifications (TSs). The cause of both C02 systems inoperability was attributed to the equipment failure of the time delay relays which control the automatic function of the systems exhaust fan Licensee corrective actions included the replacement of the affected relays, the suceessful completion of the required TS surveillance tests, and the implementation of a structured daily review by plant management of all TS Action Statements in effect to ensure repairs are made, when possible, prior to expiration of TS time limit Salem LERs Unit 1 LER 89-004 Revision l addresses the completion of an Engineering Evaluation conducted subsequent to a January 1989 event in.which a reactor coolant pump*

breaker surveillance had not been performed as required. The results of the evaluation indicated. that the breaker switches had operated correctly in the past, even though no

• specific surveillance tests had been performed. The inspector reviewed the revisions to the LER, and no deficiencies were note LER 90:-021. (See Section 7.1.C)

LER 90-022 concerns the entry of Salem Unit 1 into Technical Specification 3.0.3 in

• order to accomplish the repair of a cold leg safety injection line relief valve. This event was described in NE.C Inspection 50-272/90~19. No inadequacies were noted relative to this LE LER 90-023 addresses a discrepancy between the required surveillances for Unit 1 and Unit 2 service water system check valves and the requirements of the Salem Inservice Testing (IST) Program Manual. The discrepancy involved a difference in the testing intervals required by the IST program versus the normal surveillance interval, and the root cause of the event was attributed to inadequate administrative controls.. As a corrective action, the licensee modified the IST program to correct the -scheduling discrepancy _and corrected the recurnng task in the computer based work activity*

system accordingly. No inadequacies were noted relative to.this LE LER 90-024 (See Section 4.3.1.B).

LER.90-025 discusses a string of four Engineered Safety Feature (ESF) actuations whlch had occurred due to electrical signal spikes in* the Control Room Air Intake Radiation Monitoring System (RMS) alarm circuitry. The four ESF actuations involved the automatic switching of the control room ventilation to-the accident mode of operation. The licensee eventually determined the Ca.use of the signal* spikes to b two failed capacitors in the power supply of the RMS control circuitry, whose function is to filter electrical noise. Corrective actions for the event include replacement of the failed capacitors as well as discussions with Operations and

• 'Maintenance personnel to erisure a more timely response to abnormal events in order

• to preclude their repetition, as occurred in this case. No inadequacies were noted relative to this LE *

LER 90-026 and Revision 1 to the* LER address several occurrences of ASME Code 3

. piping leakage at both Unit 1 and Unit 2. In all cases, the required NRC notifications were made, the applicable Technical Specifications were complied with, and repairs

were performed in accordance with the ASME code. The root cause of the component leakage was attributed to equipment failure, and the licensee has..

implemented a program for the upgrade of service water system piping at the Salem Station.. No inadequacies were noted relative to this LE * *

LER 90-027 concerns a Main Steamline Isolation actuation which occurred upon a receipt of a high steamline flow signal coincident with a low steamline pressure signal while the plant was in Mode 4 and heating up in preparation for startup. The root cause of this Engineered Safety Feature actuation was attributed to an equipment/design deficiency associated with main steamline flow transmitter sensing lines, and licensee. engineering is developing design modifications to correct the main.

steamline flow iiistrumentation concerns.. No inadequacies were identified relative to this LE.

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LER 90-028 addresses a Unit 1 entry into Technical Specification (TS) 3.0.3, which required that the plant be taken to Mode 3 (Hot Standby). The unit was in Mode 2 when a licensed operator noted that two Individual Rod Position Indications (IRPis) in one Control Bank and two IRPis each in two different Shutdown Banks all indicated a greater than 12 step deviation from their group demand counter, and the six IRPis were subsequently declared inoperable. The actions required if more than one analog rod position indicator (ARPI) per bank is inoperable are not directly provided for in the applicable TS and, therefore, TS 3.0.3 was entered. The root cause of the IRPis having greater than a 12 step deviation from their group demand counter was

attributed to a system design deficiency due to the inherent nature of the analog coils susceptibility to temperature changes associated with Mode changes. Short-term corrective action included a recalibration of all 53 IRPls once all rods had been inserted. Also, the ARPI.system is being considered by the licensee for an upgrade to.

. eliminate the temperature susceptibility of the ARPI coils. No inadequacies were noted relative to this LE LER 90-031 concerns the automatic* switching of the control room ventilation froni normal operation to the accident mode of operation, which is an* Engineered Safety *

Feature (ESF) actuation. The actuation resulted when the control room area radiation monitor (lRlA) spiked high due to a.technician performing a surveillance activity on a separate channel in the same cabinet as the lRlA channel. The root cause of the*

event was attributed to equipment failure associated with inadequate preventive maintenance in that the preventive maintenance program* for radiation monitors did not include periodic replacement of power supply circuit capacitors.which prevent electro-.

magnetic interference betWeen different channels sharing the same cabinet. Corrective actions included the replacement of the required capacitors in the lRlA channel a *

review of the preventive maintenance program for radiation monitors to identify the necessary replacement of additional capacitors. No inadequacies were noted relative to this LE. '

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LER 90-032 (See* Section 3.2.1.a)..

LER 90-033 concerns the discovery by a Control Room Operator that the 0 1Rl 1A/1Rl2A/1R12B Containment Radiation Monitoring System (RMS) pump operability indication was not illuminated~ The relevant RMS channels were declared inoperable, and the applicable Technical Specification Action Statements were entere *upon further investigation,.the licensee discovered that condensation had*. caused corrosion whiCh resulted in the seizing of the movable vanes of the sampijng pum Corrective actions included replacement of the affected pump, the initiationof a design change to upgrade the RMS with a more reliable pump; and the development of a,* more frequent preventive maintenance program for the pump until its replacement. No inadequacies were noted relative to this LE LER 90-034. concerns radiation monitoring system actuations caused by lRl lA (see section 2.2.1.B). No inadequacies were noted relative to this LE Unit 2 *

LER 89-016 Revision 1 addresses the root cause of the failure of three of four main steam isolation valves (MSIVs) to ciose within five seconds on October 14, 198 The licensee has completed their evaluation of the event, and has concluded that the root cause was a design concern. The orifice and drain tube in the fast closure. steam

• driven piston are incorrectly sized. The MSIVs will be modified to eliminate the

• concerns. associated with condensation collection prior to startup from the u riit 1 ninth refueling outage and the Unit 2 sixth-refueling outage. No inadequacies were noted relative to this LE *

LER 90-031 concerns the failure of three main* steamline bypass. valves to close.on July 9, 1990, w~en the manual pushbuttons for the solid state protection system main * *

. steamline isolation were* momentarily 'depressed. The valves would have closed if the operator had depressed the pushbuttons for greater than one second or if a valid isolation signal was present. An investigation identified that the control circuitry was not wired as per design.. The cause was attributed to personnel error in failure to implement a design *change circa 1980.. The circuit has been restored to the configuration shown on controlled prints; i.e., the manual pushbutton does not need to be held for arty set period of time. No inadequacies were noted relative to this LE LER 90-032 (See Section 4.3.1.B)

LER 90-033 concerns an ESF actuation of containment ventilation isolation that occurred on August 9, 1990. * This event was reviewed in NRC Inspection Report 50-311/90-19. No inadequacies were noted relative to this LE...

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LER 90-037 concerns a 2C Safeguards Equipment Control (SEC) Mode I accident

_safeguards actuation (an Engineered Safety Feature actuation) which occurred following a successful diesel generator one hour surveillance run. The root cause of the 2C SEC Mode I accidentJoading was determined to be equipment failure, namely the failure of a SEC input relay. * The licensee further determined that the relay failur would not have prevented the 2C SEC from performing its design function under*

accident or blackout conditions. The suspect input relay was replaced, and no inadequacies relative to this LER were note _ LER 90-038 concerns an ESF actuation caused by the 2Rl 1A radiation monitor (see

• . section 2.2.1.B). No inadequacies were identified relative to this LE Hope Creek LERs LER 90-016-01 is a supplement to LER 90-016 which reported the discovery of*

. inadequate diesel fuel oil analysis methods.. This supplemental report presents the *

overall results of the station Quality Assurance (QA) department investigation of the -

occurrence, as documented in QA report HQA-90-0579. The NRC's assessment of this event was detailed in NRC Inspection Report 50-354/90-16, section 8.1.A. There were no in.adequacies relative to this* LE LER90-017 discusses_a trip of the "A" Control Roo_m Ventilation (CRY) system *

during the calibration of a safety auxiliaries cooling system (SACS) pump differential pressure transmitter. Refer to sectioi1 2.2.2.B of this report for detail LER 90-018 describes a through-wall leak discovered in the "A" SACS pump on September 26, 1990. This issue-was discussed in detail in NRC Inspection Report 50-354/90-16, section 8; 1.B. There were no inadequacies relative to this LER. *

LER 90-:019 discusses an overdue semi-annual sur\\leillanee test on the drywell personnel airlock. Refer to section 4.3.2.C of this report for details. *

'LER 90-020 discusses multiple entries into Technical Specification 3.0.3 and is addressed in section 8.2.A of this report. *

LER 90-021 concerns intermediate and source range nuclear instrumentation. Refer to section 2.2.2.A of this report. -

9.2 Open Items The following inspection items were followed up during this inspection and are tabulated below for cross reference purposes:

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10.0 '

1 Item Section Status 272/88-17-01 7. Closed 272/89-27-02 8. Closed

311/87-18-03 2.2. Closed item Section Status.*

354/88-22-01 4.3~ Closed 354/88-80-01 4.3.2.D. r Closed 354/88-80-02 4.3. Open

' 354/~8-80-03 4.3. Closed 354/88-80-04 4.3. Closed

'354/89-02-01 8. Closed MEETINGS Resident The inspectors met with Mr. S. La.Bruna and Mr. C. Johnson-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 thi report does not contain information subject to 10 CFR 2 restriction. 2 Specialist.

Dates*

10/1:-5/90

'10/22-25/90 10/29-11/2/90 1 Other Subjec Emergency Opera~ng Procedures Radiological Controls

.Annual Emergency Exercise Inspection Report N /90-18

' 272/311/90-25 354/90-80 272/311/90-82 Reporting Inspector Walker Nimitz Amato On October 11, 1990, a meeting was held at the NRC Headquarters Office in Rockville, MD. The purpose of the meeting was for the licensee to provide to the NRC an overview of the engineering analyses performed for main steam isolation valve (MSIV) performance.. This was a followup to the mis-operation of two of four MSIVs following a June 29, 1990 reactor trip (NRC Inspector Report Nos. 50-272/90-20; 50-311/90-20). The inspectors attended the meeting. Followup of the*

licensee's activities will continue through. the routine inspection program..