IR 05000272/1992001

Insp Repts 50-272/92-01,50-311/92-01 & 50-354/92-01 on 911229-920208.Eight Unresolved Items Noted.Major Areas Inspected:Operations,Radiological Controls,Maint & Surveillance Testing & Emergency Preparedness & Security

ML18096A561
Person / Time
Site:	Salem, Hope Creek
Issue date:	03/03/1992
From:	Jason White NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML18096A559	List: IR 05000272/1992001 ML18096A558
References
50-272-92-01, 50-272-92-1, 50-311-92-01, 50-311-92-1, 50-354-92-01, 50-354-92-1, NUDOCS 9203100203
Download: ML18096A561 (28)

Text

Report No License No Licensee:

Facilities:

Dates:

Inspectors:

. Approved:

Inspection Summary:

U. S. NUCLEAR REGULATORY COMMISSION

REGION I

50-272/92-01 50-311/92-01 50-354/92-01 DPR-70 DPR-75 NPF-57 Public Service Electric and Gas Company P.O. Box 236 Hancocks Bridge, New Jersey 08038 Salem Nuclear Generating Station Hope Creek Nuclear Generating Statiori December 29, 1991 - February 8, 1992 T. P. Johnson, Senior Resident Inspector S. M. Pindale, Resident Inspector S. T. Barr; Resident Inspector H. K. Lathrop, Resident Ins P. Path *, Rea or hite, Chief, Projects ection 2A *

Inspection 50-272/92-01; 50-311/92-01; 50-354/92-01 on December 29; 1991-February 8, 1992 Areas Inspected: Resident safety inspection to assure public health and safety. The following areas were reviewed:_ operations, radiological controls, maintenance and surveillance testing, emergency preparedness, security, engineering/technical support, safety assessment/quality verification, and licensee event reports and open item followu Results: The inspectors concluded that public health and safety was assured. Eight unresolved items were identified during the period (five at Salem, two at Hope Creek, and one common). An executive summary follow PDR ADOCK 05000272 Q

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SUMMARY

. Salem Inspection Reports 50-272/92-01; 50-311/92-01 *

Hope Creek Inspection Report 50-354/92-01 December 29, 1991 - February 8, 1992 OPERATIONS (Modules 60710, 71707, 93702)

Salem: The Salem units were operated in a safe manner. Radiation monitoring system actuations were reported, and licensee actions were appropriate. A loss of the 2A vital bus occurred while Unit 2 was defueled. The 2A emergency diesel generator started and re-energized the bus. The diesel was later secured after a leak in the service water supply occurred. Subsequently, bus power was transferred from the No. 22 Station Power Transformer. Licensee actions were determined to be appropriat Effective operator actions were noted When Unit 1 was taken off-line. for six days due to a loss of circulating water pumps. Licensee investigation revealed a damaged control power cable. Actions to repair the cable and to perform additional maintenance and testing were conservative and appropriate. An unresolved item concerning Ori-The-Spot-Changes to Emergency Operating Procedures was close *

Hope Creek: The unit was operated in a safe manner. Licensee actions were determined to be appropriate in response to indications of a degraded reactor recirculation pump sea Multiple Filtration, Recirculation and Ventilation System fan starts and Control Room

. Emergency Filtration System trips were appropriately respon.ded to by the license Operators promptly responded to an increasing main steam tunnel temperature event caused in part by incorrect installation of steam tunnel backdraft dampers. This issue is unresolve RADIOLOGICAL CONTROLS (Modules 71707, 93702)

Salem: Periodic inspector observation of station. workers *and Radiation Protectiori personnel implementation of radiological controls and protection program requirements did not identify any deficiencies. Radiological controls for the Un~t 2 containment were well establishe Hope Creek: Periodic inspector observation of station workers and Radiation Protection personnel implementation of radiologiCal controls and protection program requirements did not identify any deficiencies. Licensee actions in response to a spill in the service radwaste building were good. Overall, housekeeping in the radiological control area was excellen.

. *. MAINTENANCE/SURVEILLANCE * (Modules 61726, 62703, 73753)

• Salem: Routine observations did not identify any deficiencies. Licensee surveillance testing.*

revealed problems in testing the Unit 1 turbine steam admission vaive control. Effective system engineer troubleshooting u.ncovered several causes, all of which were appropriately addressed. During the six day forced outage, the licensee conducted ~xtensive tests of the

.* Unit 1 turbine trip system. A small build-up of sludge was discovered iii the auto* stop oil header, but all other components functioned as designed.. The work conducted was prudent, well planned, and well performed. Service water pipe replacement activities on Unit 2 continued; the licensee's pre-outage plannfog and execution of this work was conducted in a safe and conservative manner. *Performance of the ten-year in-service inspection of the Uni reactor vessel was well organized and effectively conducte Hope Creek:. Routine observations did not' identify any deficiencies. The licensee appropriately responded to an. unplanned reactor protection system motor generator set trip during testin EMERGENCY PREPAREDNESS (Modules 71707, 93702)

An Unusual Event was declared at Saleni when the Delaware River level decreased below 83'

feet, the level at which the Salem Event Classification Guide (ECG) requires the declaratio The river stayed below this level for 20 minutes, after which time the event was terminated.*

Hope Creek did not make a similar declaration, as their ECG does'not require a declaration until the river reaches 82 feet. This item is unresolved pending the licensee's evaluation and resolution ~f the discrepancy between Salem*and Hope Cree SECURITY (Modules 71707, 93702)

Routine observation of protected area-_access and egress. showed good control by the license No deficient conditions or events wen~ identifie *

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ENGINEERING/TECHNICAL SUPPORT (Modules* 37700, 71707)

_Salem: Review of the management of engineering work activities determined that they were being performed in accordance with applicable procedures and were being properly prioritized and executed. Two items concerning the containment spray systems at both units were determined to *be unresolved: PSE&G determined the system flow response time was outside the design basis; and the differential pressure to which the system discharge isolation motor-operated valves could be exposed was found to be greater than the manufacturer's original design value. A third unresolved item concerned the licensee's identification of a.*

mechanical gagging device on a relief valve on the reactor coolant pump seal return flow *

line. At the end of the report period, PSE&G was pursuing resolution -of the three unresolved items. To date, licensee response to these issues appeared io be appropriate, Hope Creek: Review of the management of engineering work activities~ revealed performance in accordance with applicable procedures and proper prioritization and execution. On-site ammonia storage and its effect on the Hdpe Creek control room habitability is unresolve SAFETY ASSESSMENT/QUALITY VERIFICATION (Modules 50095~ 7i707, 92700, 92701, 93702)

Salem: A licensing issue was raised concerning the stop check valves in the main feedwater return lines. The valves are identified in the Salem Final Safety Anzjysis Report as containment isolation valves but are not similarly identified in the Salem Technical Specifications. In addition, these valves have not been environmentally qualified. Further, the assumed auxiliary feedwater flow was found to be outside the design basis. These iterris remain unresolved pending licensee action to complete evaluations and establish corrective measures. Station management displayed a conserVative approach with respect to operation Hope Creek: Management's actions taken to review the Hope Creek turbine generator trip

. system and overspeed protection were determined to be comprehensive and displayed a conservative approach to plant safety.

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DETAILS SUMMARY OF OPERATIONS Salem Units 1 and 2 Unit 1 operated at power throughout the report period except for a forced outage which occurred when three circulating water pumps lost power on January 21. The unit remained off-line, but critical~ for seven days as repairs were accomplished on the. feectwater regulating valves and maintenance was performed on the main turbine. The unit.retilrned to service on January 27 and remained iD. service through the end of the perio Unit 2 remained in its sixth refueling outage throughout the entire report period. In addition to normal refueling outage activities, significant work was accomplished on the main turbine, including replacement of the high pressure rotor and the generator stator. At the end of the period, preparations were underway to begin returning fuel* to the reactor vesse.2. Hope Creek The Hope Creek unit operated during the entire period.. Load reductions were-made to accomplish testing and maintenance. At the end of the period, the unit had operated for 270 continuous day.

OPERATIONS Inspection Activities The inspectors verified that the facilities were operated safely and in conformance with regulatory requirements. Public Service Electric and Gas (PSE&G) Company management control was evaluated by direct observation of activities, tours of the facilities, interviews and discussions with personnel, independent verification of safety system status and Technical Specification compliance, and review of facility records. These inspection activities were conducted in accordance with NRC inspection procedures 60710, 71707, and 93702. The inspectors performed normal and back-shift inspections, including deep back-shift (11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br />)

inspections as follows:

1/5/92 1/24/92 2/3/92 Inspection Hours 7:00 a.m. - 1:00 :00 p.m. - 8:00 :00 a.m. - 7:30.2 Inspection Fmdings and Significant Plant Events 2.2.1 Salem * Loss of 2A Vital Bus On January 4, 1992, with Unit 2 defueled, a loss of the 2A vitaf bus occurred. At 9:47 p.m., after an offsite power supply planned outage, operators were swapping 2A vital bus from the No. 22 station power transformer (SPT) to the No~ 21 SPT. A-13.8 KV breaker failure in the No. 21 SPT supply resulted in a loss of power to the 2A vital bus. The 2A emergency diesel generator (EDG) started and re-energized the vital bu Subsequently, a leak occurred in an elbow to the 2A EDG service water supply piping near valve21SW39. At 10:25 p.m., operators swapped power back to the No. 22 SPT, and the

'2A EDG was secured. Licensee followup found a blown potential transformer fuse on N SPT. The fuse was replaced, and the No. 21 SPT feed-er breaker was returned to servic Repairs were performed on the 2A EDG service water piping. The licensee had performed ultrasonic checks of this and similar piping for other EDGs. No wall thinning was foun This leak was determined to be a pit near a weld, probably due to microbiologically induced corrosion. The affected pipe was repaired. The EDG service water piping is scheduled for replacement next outag The inspector reviewed licensee actions, including control room logs and the draft incident report. The inspector concluded thaf the licensee responded appropriately relative to the operat?r actions for the loss of the vital bus, service water repairs, and breaker failur Unit Turbine Taken Offline Due to Loss of Circulating Water Pumps On January 21, 1992, a secondary plant transient occurred at Unit 1, resulting in a manual load reduction and subsequent manual turbine trip._ The unit was operating at 100% power with two of the six circulating water (CW) pumps out of service for maintenance. At 3: 17 p.m., two of the four operating CW pumps automatically tripped due to an apparent loss of breaker control power. Plant operators entered the appropriate abnormal operating procedure (AOP) and manually initiated a rapid load reduction as required. Power was stabilized at 20% while the licensee attempted to determine the cause of the CW pump trip. However, the cause was not readily apparent, and the CW pumps could not be restored. Therefore, the operators manually tripped the turbine as required by the AO Three of the six CW pumps (for each Salem unit) are supplied with temporary electrical _

power from the Hope Creek 13.8 kV switchyard due to load concerns in the Salem 13.8 KV switchyard. In this event, the two CW pumps that automatically tripped were electrically powered from Hope Creek. One of the two CW pumps that was already out of service for maintenance was the third Unit 1 CW pump powered from Hope Cree The licensee's followup investigation identified that a cont~ol power cable, -common to the

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three Hope Creek powered-CW pumps, was damaged. The cable was underground -and was found to be damaged by a_ cable clamp from an adjacent cable. No related work,.including _

excavation or digging, was being performed at the time of the event that may have caused the cable damage. The licensee replaced the damaged cable and routed it above groun9 to prevent a similar occurrenc *

Since the turbine unit was removed from service, the licensee performed additional activities, including the repair of body-to-bonnet leaks in the feedwater regulating valves and_ testing of the turbine control system~ iricludiilg the trip sok~noids. _(See Sections 4.3: 1 A "and B of this report for additional detai~s on the turbine control system testing). The reactor unit remained in a critical condition, Moc1e 2 (Startup), while the above activities were accomplished. -

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-_ The inspector responded to the control room during the plant transient and concluded that the operator actions were timely and.in accordance with procedures. In addfrion, the inspecfor *.

monitored the cable repair activities and the subsequent return of the unit to service* on January 27, 199 *

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The inspector.concluded that the licensee's decision to maintain the unit off-line to* conduct _-

additional maintenance and turbine control system testing was conservative and appropriat Operator actions in response to transient were noted as being eff~ctiv Radiation Monitor Engineered Safety Feature (ESF) Actuations _ -_

The following ESP ~ctuation_s occurred and were reported by PSE&G during the period:

Units Radiation Monitor Date Time

lRlB January 17, 1992 10:47 &2 2R1B January 23, 1992 4:22 p.m. *

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2R1B January 23, 1992 5:20 p.m. -_

1,RlA, lRllA, 1R13A, 1Rl9A January. 30, 1992 9:03 These events continue to be i~d1cative of the degraded radiation monitor system (RMS).

Systems responded as designed causing-*a combination of containment ventilation isolations, _

control room ventilation starts and/or steam generator blowdown line isolations.. The causes--

of the January 17 and January i3, 1992 events were either spunous high radiation signals or failed relays. The January 30, 1992 event was due to personnel error while maintenance was being performed on a radiation monitor. Licensee corrective actions included short term and-long term equipment upgrades.*_ (See section 4.1 for RMS upgrades.) The inspecto *

reviewed the licensee actions taken in response to the events. No unacceptable conditions were note O:i>eii Item FoUowup. *

• (Closed) *Unresolved Item (50-272&311/91-11-0i)..

On-The:-Spot~Changes (OTSCs) t. Emergency Operating Procedures (EOPs). In June 1991, when the* NRC administered

• . *,written and operating examinations to candid;ites for operating* licenses at Salem, a post:-'

examiria:tion comment raised a concern over the possibility of.making OTSCs to EOP PSE&G stated that changes. to the EOPs are not intended to be handled in a similar manner

• as* normal operating procedures due to their importance to safety, yet no controlling procedure made any distin~tion.between EOPs and other implelilenting procedures with

. * regard to the procedure change process. ~he procedure change process at Salem is controlled by station administrative procedure NC.NA-AP.ZZ-0043(Q), "Preparation, Review and Approval of Procedures;,; which references Administrative Directive AD-44,

"Emergency/ Abnormal* Operating Procedure Program," for ~he _handling of E_OPs and Abnormal Operating Procedures (AOPs).

In. response to the NRC concern, PSE&G changed AD-44 to specify that OTSCs are not

• allowed. for AOPs no_r EOPs. The sentence, "ON-THE-SPOT-CHANGES ARE NOT PERMITTED _FOR ANY BOP (AOP), "*was added to the paragraph in AD~44 that addresses

. making 9hanges to EOPs (AOPs). The inspector verified the implementation of these changes and discussed them with Various members of the Operations Department. *Th inspector concluded that the licensee actions in response to the concern were effective and adequate,. and. the. unresolved i,tem is closed..

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2.2.2 Hope Creek R~actor Recirculation Pump Seal Degraclation

.. *Early in January 1992, operating personnel noted d~reasing pressu~es associated with the No. 2 (outboard) seal for the A reactor recirculation pump. Normal seal pressure is

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approximately one-half of reactor pressure or abo.ut 510 psig. Observed No. 2 seal pressure *

had decreased to between 370 - 410 psig.. The licensee instituted increased monitoring of No. 2 seal parameters including seal _temperatures, pressures, and flow The inspeetor verified licensee actions, independently monitored seal parameters and reviewed applicable procedures. While operating procedures existed for alarm response and complete seal failure, there was no procedure for a single seal failure. The inspector discussed this item with operations managem-ent personnel. The licensee stated that although

_no procedure existed for single seal failures, operators were trained on the simulator to recognize and to react to single and complete seal failures. The inspector noted that.each.

. seal is designed to withstand full reactor coolant system pressur The inspector concluded that licensee actions were appropriat *

• Multiple Filtration, Recirculation and Ventilation *system (Fil.VS) and Control Room Emergency Filtration *(CREF) System Problems

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On January 2, 1992 'and 'January 14, 1992, spurious starts of the "F" and "E" FRVS reeirculation fans, respectively, were noted by control room operators. In each Case the fan was secured after running for a short time.. *The apparent cause was an accumulation of moisture in a suction low flow pressure transmitter. This was a previously identified problem for which _a design change package (DCP) 4EC-3226 had been developed (see Licensee Even_t Reports 91-19-00 and 91-19-01 for a foll discussion of ~his issue) but not yet implemented due to the potenticil seram risk. * The inspector noted that the licensee had scheduled implementation of the DCP for the upcoming outage in March 199.

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On January 4, 1992, the "B" control room ventilation train tripped. The "A" train automatically started, then tripped a short time later. Operators were able to start the "A"

• train manually. No cause was found for either trip and ~he "B" train was returned to s¢ivice later that day. On January 28, 1992, with the reactor at 100% power, the "A" train was in service and was secured in order to perform a surveillance on the "B" train. The ;'B" train was started, then tripped three minutes later. Operators restarted the "B" train, which ran for four minutes and tripped again. Operators then placed the "A" train back in service,

• which tripped after three minutes. Both trains were declared inoperable and Technical Specification (TS) 3.0.3 was entered at 8:38 p.m. (TSs allow one train of CREF to be

. inoperable for seven days, but there is no provision for both trains to be inoperable when the

• * plant is in Condition l. Refrigerant was added to-the "A" chiller and the "A" train was successfully restarted at 10: 19 p.m. After running for thirty minutes with ail parameters

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normal, the "A" train, was declared operable and TS 3.0.3 exited at 10:52 p.m. Th~ reactor power decrease was halted at 95 % and the unit was subsequently returned to full powe The licens~'s investigation into these and other recent CREF reliability problems was*

ongoing; however, a number of design issues had been identified, including:

The chiller unit for each train was poorly suited for operation at load with cool outside air temperatures..

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Chiller refrigerant usage appeared excessive ~s low refrigerant pressure. was a frequent cause of trip Trip setpoint values conflicted with the instrument data sheet The inspector discussed the* issue of system reliability with licensee management. The licensee indicated that the root cause may be weather related, as both units had proved very reliable during the warmer months. However, such reliability appeared diminished when outside air temperatures were low and the loads on the units were reduced. The inspector noted that tl}e licensee was addressing this issue in* a sufficient manner relative to the overall low safety significanc *

6 Unplanned Power Reduction Due to High Main Steam Tunnel Temperature On January 8, 1992, while investigating elevated main steam tunnel (MST) temperatures, operations personnel observed steam packing leaks from three valves in the MST, KP-HV-5438B, AB-HV-3631A and AB-HV-3631B. (Normal temperatures are approximately 115 degrees F.) All three valves form a part of the outboard main steam isolation valve sealing steam (MSIVSS) system boundary. By January 13, 1992, MST temperatures had stabilized at about 130 degrees F. Temperatures were being monitored and recorded three times a da On January 16, 1992, while performing a functional retest on the "E" and "F" filtration, recirculation, and ventilation system (FRVS) vent fans, the MST backdraft dampers isolated on high temperature. Reactor power was immediately reduced from 100% to 87% in accordance with the appropriate abnormal operating procedure, OP-AB.ZZ-206. A visual inspection of the MST determined that no unknown steamJciks existed, and the backdraft dampers were reopened. Difficulties were experienced in reopening the suction damper Consequently, the dampers were mechanically clamped in the open position. The highest MST. temperature noted was 146 degrees F. The MSIV s are designed to isolate at 160 degrees F. Once MST temperatures returned to their pre-event value of 128 degrees F, the reactor was returned to full power on Janu~ 17, 199 *The licensee determined that the retesting of the FRVS fans diverted some of the air flow to the MST and that the backdraft dampers isolated as designed when MST temperatures reached 135 degrees F. The backdraft dampers prevent the passage of steam from the.MST to areas of the reactor building should a steam rupture occur in the MST. The difficulty in *

opening these dampers was due to equipment operator unfamiliarity with the operating mechanis The inspector noted that the actions taken by operations personnel to control and red9ce MST temperatures were prompt and effective in averting a major plant transient which would have occurred had MST temperatures reached 160 degrees F and the MSIVs automatically close Good support. was provided by both system engineering and maintenance personne During the root cause investigation, the licensee noted that the MST suction side backdraft dampers (two in series) appeared to have been installed backwards. A check of the other 24 sets of backdraft dampers throughout the reactor building was performed and, for each room fitted with these dampers, the suction side dampers were also installed backwards. In this. *

configuration, analysis indicated that the suction dampers could be forced partially open by a differential pressure (dp) of about 0.25 inches of water (0.5 inches total dp). At the close of the report period the licensee initiated evaluation of the effects of a postulated steam rupture event on the surrounding rooms and equipment. Additionally, licensee management initiated action to reinstall the dampers in the correct configuration. This. issue is an unresolved item pending NRC review of the engineering evaluation on room and equipment effects and corrective measures taken. (UNR 50-354/92-01-01).

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7 RADIOLOGICAL CONTROLS 3.1 *

Inspection Activities

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PSE&G' s conformarice with the radiological protection program *was verified on a periodic basis. These inspection activities were* conducted in aQcordance with NRC inspection procedures 71707 and 93702.

. 3.2.1 Salem Containment Tour *

• The inspectors periodically toured the Salem Unit 2 co~tainnient during the current refueling outage period. Items checked included access controls, use of anti-contamination clothing, worker radiation practices, dos1metry and exposure control.s, and work in progres Radiation protection personnel were inter-viewed and found to be very knowledgeabl * Licensee efforts to reduce dose. rates during* the service water pipe replacement effort were

,also observed and determined to be effective* in minimizing exposure to workers..These efforts included the extensive application of temporary shielding on high.:.dose rate piping and *

selected valve stations.. Pre-outage evaluation of affected pipe-hangers was conducted to ensure sufficient support for the added loa The inspector concluded that radiological coritrols_for the Unit 2 containment were ver good:*

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. 3~2.2 Hope Creek A..

Radioactive SpiUFrom The Waste Filter On January 1, 1992, radwaste operators lined up to process the contents of the 11A 11 waste collector tank to the 11A 11 waste sample tank through the waste filter and waste derhineralize At the time, the 11 A" flow drain collector tank was in service. About one hour after processing began, operators noted an increased input to the 11A 11 floor drairi collector tan Upon investigating, the operators determined that a leak existed in the waste filter room..

The filter was isolated. Contamination was limited to the_waste filter room (the filter was the only piece of equipment in that* room) and a portion of the adjacent waste filter holding pump room where water had spilled through a wall penetration. Approximately 4,000 gallons were spilled, as determined by the change in floor drain collector tank level. The licensee's investigation indicated that a flanged pipe connection for the waste.filter was the.

source. of the leak. This same connection had leaked previously. Consequently, the flange

. gaskets were replaced in May 1991. Inspection of the gasket material revealed that it was *

pinched and most likely was impaired since the May 1991 installatio *

• The inspector discussed this event with radiation protection and maintenance personne They indicated that any maintenance performed in the waste filter room was complicated by dl.fficult working conditions such as cramped spaces and the need for wearing a double layer.

of protective clothing and a respirator. The inspector noted good cooperation between the

affected groups and that the repairs were completed expeditiously with low totalpersonnel exposur.

. Radiologically Controlled Area (RCA) Housekeeping The inspectors noted excellent hpusekeeping in the RCA.. Most areas were accessible and-the number of contamination areas* were.at a minimum.. The licensee continued to paint plant *

areas in order to improve the control of contaminatio * *MAINTENANCE/SURVEILLANCE TESTING Maintenance InSpection Activity -* *

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The inspectors observed selected maintenance activities on safety-related equipment to ascertain that. these activities were. conducted in accordance with approved procedures, Technical Specifications, and appropriate industrial codes and standards; These inspections were conducted in accordance with NRC inspectfon procedure *6270 *

Portions of the following activities were observed by the iilspector:

.. Work Order. (WO) or Salem 2 Salem 2 Salem 2 Salem 1 Procedure or Design Change Package 2SC-2229 2EC-3086 2SC-2166 2EC-3043 2EC-3045 2EC-3041 Various Description Uninterruptible power supply for radiation monitoring system (RMS)

RMS upgrades Service water system pipe.

replacements Turbine valve and control system troubleshooting

• Hope Creek

.. WO 911115143

, Hope Creek WO 910503133

Turbine auto stop oil and trip solenoid. *

qiaintenance

"A". recirculation pump sea.I purge relief valve repair

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The maintenanee activities inspected were effective with respect. to meeting the safety objectives of the maintenance progra *

4.2... S.urveillance Testing Inspectio:n Activity The inspeetors 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 procedure~, and NRC regulations. These inspection. activities were conducted in accordance with NRC inspection procedure 6172 The following surveillance tests were reviewed, with portions witnessed. by the inspector:

. Salem 1*

Hope Creek Hope Creek. "

Procedure No.

SP(0)4.3.4.2 *.

OP-ST.GU-001 OP-IS.BH-001 Turbine y alve Stroke Testing Filtration, Recirculation and Ventilation System (FRVS) Monthly 11A 11 Standby Liquid Control Pump 92 Day Inservice Surveillance Test The surveillance testing activities inspected were effective with respect to meeting the safety

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objectives of the surveillance testing program.*. * Inspection Findings 4.3.1 Salem Unit 1 Turbine Valve Surveillance Testing On January 12, 1992, Unit 1 reactor power was reduced to 85 % to perform turbine valve surveillance testing per procedure SP(0)4.3.4.2. This procedure individually cycles. the following turbine steam admission valves: stop valves, governor valves, reheat stop valves, and intercept valves. The stop and governor valves were tested satisfactorily. However, the reheat stop and intercept valves would not stroke from the control room test pane...

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• Licensee troubleshooting de.tetmined the following: (1) two limit switches were not making up; (2) control room test pushbuttons were not functioning; (3) a fuse was blown; and (4) burnt wire was noted in the electro-hydraulic control (EHC) cabfoet. The licensee repaired items (1), (2), and (3).and* retestec;l the valves satisfactorily except for llE reheat stop and *

..intercept valves:* Additiqnal.verification and inspection activities determined that the.burnt wire affected the test circuit for one of the llE reheat stop and intercept *valves. A jumper wasjnstalled to allow testing. *Subsequently, all valves were stroked satisfa.ctorily. During the Unit 1 turbine outage (January 21-27, l992), the daniaged EHC wfre was replace The inspector reviewed licensee activities, indudirig observation of testing and*

. troubleshooting.* The inspector examined the damaged wire* in the EHC cabinet and discussed these issues with engineering *and operations personnel. Licensee actions were determined* to* be appropriate. *System engineering personnel were noted as being *

knowledgeable and very. involved in the troubleshooting and corrective actio.

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. Unit l Main Turbine Auto Stop Oil and Trip SolenoidPreventive Maintenance During the Unit 1 forced outage of January 21-27, 1992 (see paragraph 2.2.1.B of this report), and in response to the November 1991 Unit 2 turbine generator failure; PSE&G

. conducted extensive tests and inspections of the Unit 1 turbine trip system while the unH was o.ff-:line. Salem Technical Department system engineers developed a maintenance work order with several work activities, including independent energization of the overspeed protection controller (OPC) and emergency trip solenoids, inspection of the electro-hydraulic control fluid orifice plates for debris, and calibration of the auto stop oil header low pressure switche *

The inspector discussed the work plan with the Salem system engineers, review~ the work order procedures used Jo accomplish the work activities, and observed various portions of.the solenoid testing and pressure switch calibration. The preventive maintenance revealed a small amount of sludge build-up in the auto stop oil header but all components functioned as designed. The inspector concluded that the work performed. on the Unit 1 turbme was *

prudent, well planned, and well performed.. Service Water Pipe Replacements The inspector conqucted auxiliary building, *service water structure, and containment walkdowns to observe service water pipe replacement work in progress on Salem Unit Items inspected included mruntenance of pipe )nternal cleanliness, hou.sekeeping and

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• scaffolding controls, and handling and rigging of pipe sections. Liceril?ee control of work was determined to be in accordance with licensee. and NRC requirements. The inspector discuss~ pipe replacement activities with engineers and the project manger. These.

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personnel were determined to be knowledgeable. The inspector concluded that the licensee's.

pre-outage planning and executiOn of the service water pipe replacement work for the current -

outage has been conducted in a Sa.fe and C<?nservative manne Inservice Inspection ofThe Salem Unit 2 Reactor Vessel

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' On January 23, 1992, an inspection was performed to witness inservice inspeetion of the*

• Salem Unit 2 reactor vessel. The licensee was in the process of conducting the, ten-year inservice inspection of the reactor vessel using an automated ultrasonic Programmed and Remote.(PAR) device; One hundred percent of all accessible welds in the vessel were

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_ planned for the e~amination. Theinspector observed ultrasonic examination of the

._:meridional welds in the bottom.head. The procedure.in use was VS2.SS~lS.RCE-0042(Q).

The data were evaluated on-line by a computer while ultrasonic testing was in progress.. The.

licensee's program provides for reviewing the data by the computer and* qual'ified*personnel at the end of the examination. Review of _the procedure and the personnel qualification

• . certification was found to be satisfactory. The l~censee' s contracted personnel wer * proficient in the use of the automated ultrasonic equipment. The performance of inservice.

. inspection was well organized and effectively conducted.

. The licensee f~und a linear indicatio~ in the core barrel by visual examination during the.

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fifth refueling outage (1990). During the current outage; the licensee planned to evaluate the indication by eddy current examination using a pancake probe following the vessel

• examination. If the eddy current examination confirms presence of a defect, an ultrasonic

. examination would be done to determine the depth of the defeet. The inspector discussed the evaluation process planned by the licensee. No una.cceptable conditions were identifiec * 4.3.2 Hope Creek Unplanned.Engineered Safety Feature (ESF) Actuation Durmg Surveillance Testing On January 21, 1992, while performing a surveillanceJest on the "A" Reactor Prqtection System (RPS) motor generator (MG) set breakers, the "A" RPS MG set" power feeds (AN410 and BN410) and generator output breakers tripped. The breaker trip resulted in a half-.

scram, reactor water cleanup system (RWCU) isolation, and closure of the inboard *main steam line drain valve. Operators placed the "A" RPS bus on an alternate power supply, reset* the half-scram and isolation signals and restored the RWCU system to service. An ENS call was mad The licensee determined that an apparently faulty voltage test meter caused the breakers to trip open when a technician was attempting to read the voltage on the output side of the breaker. * Due: to extensive damage to the internals of the meter, the exact nature of the fault could not be determined. The licensee sent the meter off-site for independent anaiysis; the results of which indicated that the meter was not the cause of the breaker trip._ The test device was within its calibration frequency and had been properly ranged by the technician

prior to tuong his readings.. However, the technician apparently inserted the.test leads into

• the incorrect plug jacks on the face of the meter. The licensee was evaluating this issue

• further in light of this fi~ding when the' inspection period ende *

-The inspecto_r reviewed the event~.including the licensee's investigation. The inspecto concluded that, to date, licensee actions appeared appropri_ate. * * EMERGENCY PREPAREDNESS **Inspection Activity*

The inspector reviewed PSE&G's co.nformance with 10CFR50.47 regarqing implementation of the emergency 'plan and procedures. In addition, licensee event notifications arid reporting requirements per 10CFR50.72 anci 73 were reviewe.2 Inspection Findin_gs

. Unusual Event Due to Low River Level *

• Salem. declar~ an Unusual Event at 3:21 p.m. on January 16, 1992, when the Delaware*

. River level decreased to below 83 feet. Emergency Classification Guide, (ECG) 12G * *

required this declaration. The low river level was caused by a low tide combined with a*

. strong northerly wind causing tide movement away from the river fevel sensing area (circulating water structure). The level decreased to a minimum of 82. 7 feet; and by 3:41 p.m., the level increased to 83.8 feet, and the Unusual Event was subsequently terminate The equivalent Hope Creek ECG required an Unusual Event if river level decreased to below 82 feet. Actual Hope Creek measured level * (at* the Hope Creek service \\\\'ater structure). was between 82 and 83 feet. Therefore, a similar declaration was neither required nor made for Hope Cree.

The inspector reviewed control room logs, the Salem and Hope Creek ECG's, and the*

incident report. The Salem ECG deelaration was appropriate and timely. However, the inspector *questioned why the two facilities pad different ECG's. Emergency preparedness personnel responded that the difference was based on riot having Hope Creek and Salem event declarations simultaneously. The inspector noted that this was the third Unusual Event at Salem in the last two years due to low river level apparently.caused by tidal and wind effects. *

The licensee* stated they would review the river levels with respect to emergency classifications for station consistency and as a result of this tidal/wind effect. Further, other

. ECGs would also be reviewed for common type facility events. This item remains unresolved pending completion of licensee actions and subsequent NRC review (UNR S0-272&311/92-01-01; 50-354/92-01-02).

13 SECURITY Inspection Activity PSE&G's conformance with the ~urity pr~gram was. verified ori a perlodic basis, including.

the adequacy of staffing; entry control, alarm stations, and physical boundaries. These*

inspection activities were conducted in accordance with NRC inspection procedure 7170. Inspection Findings

. The inspectors determined that security program implementation was appropriate.

. *ENGINEERING/TECHNICAL SUPPoRT 7~1 *.

'Salem

• Mechanical Gagging Device Found Installed on Relief Valve

_Qn January 9, 1992, the licensee identified that the Unit 2 reactor coolant pump (RCP) seal return relief valve (No. 2CV115) had an unauthorized gagging device)nstalled. The.unit was shutdown and defueled at the time of discovery. The as found condition of the gag -..

would have reduced the relieving capacity of the 150 psig relief valve. The valve is_ located inside containment, relieves to the pressurizer relief tank, and is located on the commori seal return line for all-four RCPs. *.The valv~is loeated on the RCP side of the two series containment isolation valves. *

The licensee completed an evaluation to determine* the significance and potential consequences of the as-found condition. The evaluation calculated that the pressure at which

. the seal return piping would fail was 2235 psig. Under specific applicable postulate conditions, the licensee calculated that the highest pressure in the affected line would be 1500 psig. Therefore, the pipe would not have ruptured, although such an overpressuriation would be in _excess of the 150 psig design pressure. *

The mechanical gagging device was subsequently removed from valve 2CV115, and a lift setpoint test was satisfactorily completed. Additionally, the licensee initiated inspection of all accessible relief valves on both Unit 1 and 2 to determine whether a similar condition*

• existe The licensee suspected that the gagging device was installed and l~ft on 2CV115 in April-1990 to support a system hydrostatic test to 190 psig. The inspector was informed by the licensee that the appropriate personnel would be informed of this event and of management's expectations relative to the importance of properly monitoring relief valve *The licensee initially reported this event to the NRC on January 10, i992, to comply with

.. 10CFR50.72_reporting requirements.* Ori February 7, 1992,.however, the licensee rettj3.cted *

the 10CFR50. 72 notification since the plant was not actually operated outside of the design basis (i.e. the pipe was not pressurized beyond its 150 psig design *pressure). *Additionally, the consequence of the postulated events are bounded in the FSAR by existing design basis accident..

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The inspeetor reviewed the licensee's response and followup to thiS event and found it to be acceptabfo. Pendin_g the resl!lts of the licensee's followup and evaluation of the proposed relief valve inspection, this item remajns unresolved '(UNR 50-27~&311/92-01-02). Containment Spray System Total Response Time Found Outside Design Basis On January 1_6, 1992, the licensee reported a condition outside the design basis of the plan While performing design verification calculations of. containment spray (CS) flow delivery.

time, the licensee determined that the original value was non-conservative.. Flow delivery time is the time from pump/Valve actuatioiis until systems spray flow reaches the containment. CS system total response time (including instrumentation, logic, valve and pump actuations plus the flow delivery time) thus would exceed the ass.urned FSAR. valu Re-evaluation of containment response sijowed that peak containment pressure would remain within the design basis. The*licensee concluded that they met the Technical Specification (TS) required instrumentation response time for C * A preliminary Westinghouse engineering evaluation was conducted to formalize the recalculated flow delivery time as part of the licensing basis. The* licensee plans to.submit a revision for the TS and FSAR based on a functionil analysis. The licensee based CS system

• operability on the engineering.evaluation conclusion that peak containment pressure (45~9 *

psig) for the limitin~ accident (steam line break) remained less than design value of 47 psi The inspector reviewed the licensee preliminary evaluation and discussed this item with*

system engineers. This itern remains unresolved pending completion of the licensee analysis, Licensee Event Report submittal, and subsequent NRC review (UNR 50-272&311/92-01-03)..Containment Spray Motor-Operated Valve Operability Concern The preliminary results of a PSE&G Engineering and Plant Betterment (E&PB) engineering*

evaluation for the containment spray discharge isolation valves (CS-2) indicated a conflict with the original valve specifications relative to the potential operating differential pressures across the valves and the valves' abilities to open under those djfferential pressures. Th valve supplier, Westinghouse, originally indicated that the maximum differential pressures under worst-case conditions would be 200 psid. The PSE&G calculations indicated that the valves would actually be required to operate at approximately 240 psid. The PSE&G evaluation was done in response to the requirements of NRC Generic Letter 89-10, "Safety-Related Motor-Operated Valve Testing and Surveillance".

• PSE&G informed _the NRC of their findings soon after. determining the problems and discussed resolution of the situation with the NRC resident staff, Region l staff, and*

Headquarters specialists. Pending ah actual operability determination for the CS~2 valves on both units, the licensee instituted several interim measures. These included performing maintenance on the v:alves to ensure proper. lubriC(ltion, initiating a design _change to remove the electrical thermal overload devices on the valves to increase available operator torque, and establishing of temporary control room annunciators to alert the* operators* of a degraded voltage condition on the power supply for the valves. The licensee also initiated action to.

place larger motor operators on the valves during the current Unit 2 outage and the upcoming refueling outage; To confirin present operability of the valves, PSE&G'has initiated action

.. to conduct a full~flow test under, worse case differential pressure conditions at Unit 2 while that unit is still shut dow *

The inspector found the licensee to be accurate and precise in their communication of the *

issue with the NRC and determined their interim measures to be acceptable. Pending the final determination of valve operability and the complet.ion of all design changes and tests, this concern remains as an unresolved item CUNR 212&311192-01-04>.

7.2 Hope Creek. On"."site. Ston1ge. of Ammonia and.Control Room Habitability

• . On January 31, 1992, a licensee evaluation of control.room habitability with a worst-case spill of ammonium hydroxide, a hazardous chemical used at the Salem site, concluded that the Hope Creek control.room could be advei:_sely affected. The habitability issue was raised due to actions taken at Salem following an ammonia-related incident in August 1991. (See NRC Inspection Reports 50-272/91-25 and 272/91-26 for details.) *

The evaluation of the adequacy of the design of the Hope Creek control room for postulated accidents and conformance with the requirements of Regulatory Guides. (RG) 1.52, 1. 78 and 1.95 is contained in Chapters 1.8, 2.2, 6.4 and 9.4 of the Updated Final Safety Analysis

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Report (UFSAR) and Attachments 2.2, 6.4 and 9.4 of the Safety Evaluation Report (SER).

In the aggregate, this documentation stated that there were no hazardous chemicals stored at either Hope Creek or Salem which could adversely affect Hope Creek's control roo Consideration was given to potential river transport of ammonia; however, the probability of an accident was sufficiently low to permit excluding it as a design basis even The inspector reviewed the applicable UFSAR and SER entries and discussed the evaluation with licensee management. In response to questions concerning 10CFR50. 72 reportability, the licensee stated that calculations indicated that for ammonia strengths of 27.5 % (by

weight), which had been the concentration in use at Salem at that time, the minimum time requirement from human detection to control room isolation could be satisfied. -

Consequently, although on-site ammonfa storage was not adequately addressed in the UFSAR, the design basis requirements. of RG * 1. 78 were* met. However, since action had

. been initiated at Salem to. change the concentration of ammonia *to 15 %, thereby. increasing

. the number of deliveries, a postulated accident may degrade control room *

habitability befor.e it could be isolated from the outside. The acCidentscenario involved a spill of the total contents of a tanker truck ~s it entered the site via the main sally port, which is located between the Salem and Hope Creek stations. *

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The.licensee implemented the following actions prior to on.::site arrival of the first shipment of 15% ammonium hydroxide arrived on site on February 3, 199.

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Salem would* notify the Hope Cr~k control roo~ wh,en the tanker arrived at the

_. security center and when the tanker had left the sit Upon notification of the tanker's amval, operation's personnel would isolate the Hope Creek control room's ventilation from outside air and place it in recirculation until the

• tanker had left the site..

Additionally, the licensee evaluated the effect of using an on-site* route utilizing entry via the old Salem guardhouse, which altered the worst case scenario fault from the main sally port to

.the Salem off-loading station on the south side of Unit L This evaluation indicated that a

• substantially longer period of time would be available to isolate Hope Creek's control room

. in the event of a spill than was require,

The inspector concluded that licensee actions taken to. date were appropriate io maintain Hope Creek's control room habitability within its design basis and in conformance withJhe above referenced regulatory guides. The. inspector noted that the licensee initiated action to prepare and submit the appropriate changes to the UFSAR to* refleet the on-site transport and

. storage of ammonia and any additional actions necessary to meet their design commitment *. This item is unresolved pending completion of the licensee's actions and subsequent NRC review *(UNR 50-354/92-01-03). SAFETY ASSESSMENT/QUALITY VERIFICATIO.1 Salem

. Feedwater System Containment Isolation During a review of feedwater (FW) system design documentation, the inspector identified a concern with respect to FW system containment isolation provisions. Stop-check valves (BF-22s) located on each of the four FW injection lines just outside the containment penetrations are identified in the.Final Safety* Analysis Report (FSAR) as containment isolation valves, but

• are not identified in the Technical Specification (TS) containment isolation valves (CIVs)

table.

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The inspector discussed this concern with licensee personnel and the NRR project manager and examined licensing documentation related to the issue. As originally installed, the BF-22s did not have the capability for remote actuation. Supplement 5 of the Salem Unit 2 Safety *Evaluat~on Report (SER), issued in January 1981, identified an NRC concern with this configuration and discussed the addition of remotely operated motor operators as an acceptable means of satisfying NRC requireinents. The licensee subsequently made this modification 'to both units, with the capability for actuation from the control room. The* SER provided interim acceptance of the onginal configuration, based on* other system design.

considerations, until such time as the licensee completed implementation of acceptable system upgrades. * The other system design considerations included the continued reliance on the main and bypass feedwater regulating valves (FRVs) as CIV The licensee.is currently pursuing concerns which they identifiec1_regarding motor operator

• limit switch environmental qualification (EQ) for the B-22s. Following resolution. of this issue, the licensee intends to submit a change request to incorporate these valves in the containment isolation TS. For the interim, the FRVs remain functional as the TS CIV~. The

• inspector concluded that" the containmentisolation function for the feedwater system is currently fo compliance with TSs. However, pending resolution of the BF-22 EQ issue, this

. item is unr.esolved (UNR 272&311/92-01-05).

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8.2 *

Hope Creek Main Turbine Trip System Testing Evaluation Following the November 9, 1991 turbine overspeed event at Salem Unit 2, the licensee instituted an evaluation of Hope Creek's main turbine trip system operation, testing, and preventive maintenance. * The turbine and generator were manufactured by General Electric (GE). Of particular concern was whether all relevant vendor recommendations. had been incorporated in station procedures. A review by system engineering personnel determined that station procedures generally covered most of GE's reco~mendations. However, the following two tests were not addressed: (1) an overlap test of the mechaniccil trip and master trip solenoid v~ves and (2) manual exercising of the extraction steam check valves. Several necessary enhancements to already existing procedures were also identified. This review was *

completed on November 22, 1991. The licensee immediately revised the appropriate*

' procedures. Overall, the licensee concluded that the in-place testing and maintenance of the

• main turbinetrip system provided adequate assurance of overspeed protection operability. I addition to the teehnical review, the licensee evaluated station policies and programs against the lessons learned described in the Salem significant event response team (SERT) report of.

their turbine overspeed event. In general, most of the issues raised in the SERT report were already bounded by existing procedures aild Hope Creek's technical review. Four open items were entered into the action tracking system (A TS) to ensure that they were appropriate! y addresse *

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Immediately following a preliminary assessment of the causes of the Salem event, the

• inspector conducted an independent review of *the Hope Creek surveillance and maintenance.

• programs for the main turbine and generator. While the turbine overspeed protection fonction is similar for both Westinghouse and 'GE turbines, control and actuating. devices differ markedly. (For a discussion of the Westinghouse turbine control and supervisory circuitry; see the NRC Augmented Inspection Team Report No. 50.:-311191-81.) After the inspector reviewed fifteen surveillance, maintenance*, and operating procedures and various applicable vendor technical manuals and discussed the issue with licensee technical, operations, and engineering personnel. Subsequently, the inspector concluded that the probability of an occurrence similar to Salem's was low. Actions taken by Hope Creek management, both. imi:nedfately following the overspeed event and subsequently' appeare comprehensive and conservative and appropriately addressed the open issues raised during

• their review and analysi * Inaccurate Em~rgency Diesel Generator Fuel Oil Analysis On January 31, 1992, Hope Creek received a report from an independent laboratory stating that a.Il analysis performed on a January 15, 1992 diesel fuel oil delivery had an unacceptably high carbon resident (Ramsbottom test) of between 0.41 %.and 0.47%.. The Technical Specification (TS) maximum permissible limit is 0.35 %. A high carbon content could lead.

to degraded diesel performance due to clogged injectors and increased cylinder wear. All

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• eight emergency diesel generator (EDG) fuel oil storage tanks (2 per EDG) had been "topped off" from the January 15, 1992 delivery. The "A" tank received about 1400 gallons, the remainder about 600 gallOns each. The licensee calculated, using a carbon content of 0.5 %,.

that with the amount added to each storage tank, all tanks would. still meet the TS requirement. The *license concluded that the four EDGs were operable. Additional samples *

were drawn and sent to the same lab and another facility for analysis and comparison. The EDG vendor (Colt-Pielstick) was consulted concerning the potential consequences of running with high carbon content fuel oil. Colt stated that the EDGs would run satisfactorily with O~ 7% carbon residue for the seven:-day period assumed in the a~cident analysis. Prolonged operation with such fuel, however, was not recommended and could result in the degraded performance noted above.

. On Monday, February 3, 1992, when another analysis of the same fuel by the same lab showed 0.62 % carbon residue, the licensee challenged the lab results and instituted an investigation, elements of which were ongoing when the inspection period ended. Carbon residue test results from the other independent lab indicated values in the range between

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0.08% :- 0.12%. Subsequently, the licensee determi.ned that the laboratory technician had not performed the analysis exactly as required by the test procedure and that the fuel oil, as delivered, had been in compliance with the chemistry requirements.*

The inspector closely monitored the licensee's actions relative to the operability

• determination and incident investigation and concluded that the licensee had acted

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conservatively relative to_ the EDG operability evaluation. It was noted that a similar incident

occurred in mid-1990 when difficulties were expenenced with -another fuel oil analysi Plant management determined that future fuel oil shipments would be analyzed with all results reported before any fuel was transferred to the EDG fuel oil storage tank Additional details and observations on this incident and the licensee~s activities may be found in NRC Inspection Report 50-354/92-8.

'LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPORTS, AND OPEN ITEM FOLWWUP

- _ LERs and Reports PSE&G submitted the following licensee event reports, special reports, and periodic reports, which were reviewed for accur~cy and evaluation adequac Salem and Hope Creek Monthly Operating Reports for Dec~mber 1991

_ Salem Technical Specification 4.4.6.S., a Surveillance Notification Requirement -

Report, which described the steam generator tube plugging cqmpleted during the Unit 2 refueling outag Salem Special Report 91-3, which addressed the fire protection seal impairments*

which had not been restored to functional status within seven days and are required to be reported by Technical Specification 3.7.1 No unacceptable conditions were noted.

. Salem LERs Unit 1 LER 91-32 documented an ESP actuation signal for containment ventilation isolation which resulted from a high.' channel spike on the lRllA radiation monitor. The root cause of the channel spike_ and the event was attributed to design inadequacy of the Radiation Monitoring System. The event was described in NRC Inspection Report No. 50-272/91.;28. No

deficiencies were noted relative to the LER..

LER 91-36 documented a condition that the licensee found which was outside the design

. basis. This was reported on December 13, 1991 with an ENS call. The auxiliary feedwater (AFW) flow values may have had an adverse impact on the licensing basis steam line break

- (SLB) analyses, placing both Salem units in an unanalyzed condition. -The licensee discovered this issue during the assessment of a recently developed Salem-specific model used tO generate maximum AFW flows as a function of steam generator pressure. A

• reanalysis of SLB cases indicated that the current cycle (lO) for Salem Unit 1 core and conta,inment response would remain within the licensing basis limits, thereby justifying continued operation. I:Iowever, until the AFW flow assumptions used in the SLB analyses were corrected and the effeets of the new flow values on unit operation assessed, Salem Units 1 and 2 were considered to.have been in ari unanalyzed condition: The new flow values are nonconservatively different than those described in the Salem UFSAR, section 15.4.8.2-(1320 gpm vs 2040 gpm); therefore,.Salem is considered to have been in a condition outside of its design basi '

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The root cause of the licensing basis concern is under investigat_ion. PSE&G has formed a project team to develop *and implement corrective actions to support future cycles of-operation for both Salem Units. Westinghouse.has been requested to support PSE&G's --

efforts to determine the basis for the AFW flow values used in the SLB analy~es. Also,

• 10CFR21 reportability is being reviewe The inspector reviewed the LER and UFSAR and discussed this item with appropriate

_ licensee personrieL Pending completion *of licensee analysis ~d subsequent NRC review,

___ this item is unresolved (UNR 50-272&311/92-01-06).

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LER 91-37 documented the licensee's discovery that the plant vent effluent samples were not

' obtained as required by_ the' Salem Technical Specifications. The samples are obtained from the 1R41 plant vent fow level radiation monitor flow path._ On Decerrib_er 16, 1991, the -

1R41 channel was de-energized in order to perform maintenance, ~d the sampling line flow

• went into a* recircuiation mode, preventing the collection of a representative effluent sample. *

This condition existed for approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, before Operations Department personnel-restorecl the sample flow path. The root cause of the event was determined by the licensee to be inadequate administrative controls, in that controls had not been implemented to ensu:re-that Operations personnel would be aware that de-energizing the 1R4l channel would, by design, result in the de-energization of the sample flow punip. To prevent the situation from recurring, PSE&G plans to revise the Tagging Request Information System and the appropriate operating procedures. The inspector determined the planned corrective actions to - -

be appropriate and tlie LER to be satisfactor LER 91-38 discussed the* Salem control room habitability concern raised by -the potential release of ammonium hydroxide ~tored on site. This issue was documented in NRC Inspection Reports 50-272 and 311/9l-25, 91-26, 91-32, and 92-01 and remains an Unresolved Item. No inadequacies were noted relative to the LE. Unit 2 LER 91-20 documented an ESF actuation, a containment ventilation isolation, which resulted *

from an alarm on the containment noble gas radiation monitor on November 22, 1991. The monitor alarmed when maintenance workers cut into *the leak-off line from* the reactor coolant drain tank, allowing the contained noble gases to escape into the containment. At the

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time of the *event, the containment equipment hatch was.open, yet the auxiliary. building ventilation maintained containment at a negative pressure. * The licensee is evaluating if a release to the -environment occurred and will include the results of that evaluation in the next

• • *.. * Radiological Effluent Release Report. The root cause of the. event was -identified. as

• personnel error as a result of the maintenance workers; inattention to detail, and corrective

. disciplinary action was taken with all involved personnel.. No inadequacies were noted relative to this LE *

LER.91-21 reported the licensee's failure to perforfl1 the functional test of the waste gas analyzer as required by the Salem Technical Specifications. 'The cause of the missed..

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surveillance test was an automatic reschecluling of the test by the computer u,sed to schedule and track outage work. The root cause of the event was personnel error, in that neither the Outage Planning Department.nor.the Technical Specification Surveillance Administrator*

.identified that a required* surveillance test.had been rescheduled past its over due date. The functiona.I test was performed on the channel. the same day the delinquent condition was ;

identified. Corrective actions taken by PSE&G included disciplining the concerned personne ~d reviewing. the applicable administrative procedures to ensure scheduling responsibilities

'for surveillance tests are adequate. No inadequacies were noted relative to this LE Hope Creek None-9.2 Open Items The following previous inspection item was followed up during. this inspectio~ and* is tabulated below for cross reference purpose.Sit Report Section 272&311/91~11-01 2.2. Closed

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Hope Creek None I

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1. EXIT INTERVIEWS/MEETINGS 10.1 * Resident Exit Meeting

• *The inspectors met with Mr. C. Vondra and Mr. S. Funsten and other PSE&G personnel.*

periodically and at the end of the inspection report period to summarize the* scope arid findings of their inspection activitie * Based on Region I review and discussions with PSE~G, it \\Vas determined that this report

• does *not contain information subjeet to 10 CFR 2 restriction * 10.2. Specialist Entrance and Exit Meetfugs Date(s) *

. 1/27-2/14/92

• Subject

• Electrical

• Distribution System Functional Inspection *

10~3 Management Meeting Inspection.

Report N. 354/92-80 Reporting Inspector

. Cheung An enforcement conf~rence was held with PSE&G Salem and *corporate management on

• February 4, 1992 in the regional.office. The results will be forwarded under separate correspondenc *