IR 05000272/1993002

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Forwards Insp Repts 50-272/93-02,50-311/93-02 & 50-354/93-02 on Stated Dates.Noncited Violation Noted
ML18096B371
Person / Time
Site: Salem, Hope Creek  PSEG icon.png
Issue date: 03/25/1993
From: Wenzinger E
NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To: Miltenberger S
Public Service Enterprise Group
Shared Package
ML18096B372 List:
References
NUDOCS 9304060136
Download: ML18096B371 (39)
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Text

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Docket Nos. 50-272 50-311 50-354 Mr. Steven r.' r.

//f\\1*." 2 5 i99J Vice President and Chief Nuclear Officer Public Service Electric and Gas Company P.O. Box 236 Hancocks Bridge, NJ 08038

Dear Mr. Miltenberger:

SUBJECT:

SALEM AND HOPE CREEK RESIDENT INSPECTION NOS. 50-272/93-02; 50-311/93-02; 50-354/93-02 The enclosed report documents an inspection to assure public health and safety, conducted by Mr. T. Johnson-Senior Resident Inspector and other members of the NRC resident and regional staff at the Salem and Hope Creek Nuclear Generating Stations for the period between February 7, 1993 and March 13, 1993. The inspectors discussed the findings Of

  • -. this inspection with Messrs. V. Polizzi and R. Hovey of your staff.

Within the scope of this inspection, the inspectors noted that your facilities were operated in a safe manner commensurate with public health and safety. However, one non-cited violation involving the failure to restore the 2H bus underfrequency protection to service following-testing was identified at Salem. The details of this matter are described in the report. Your prompt and appropriate corrective actions permitted us to exercise discretionary enforcement for this self-identified violation.

Consequently, no reply to this letter is required.

  • Your cooperation with us is appreciated.

Sincerely, ORIGINi\\L SlGNrn 8'{

EDWARD C. WENZiNGER Edward C. Wenzinger, Chief Projects Branch No. 2 Division of Reactor Projects

Enclosure:

NRC Inspection Report Nos. 50-272/93-02; 50-311/93-02; 50-354/93-02 9304060136 930325 PDR ADOCK 05000272 Q

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Report Nos.. 50-272/93-02 50-311/93-02 50-354/93-02 License Nos. DPR-70 *

DPR-75 NPF-57 Licensee: *

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

Salem Nuclear Generating Station Hope Creek Nuclear Generating Station Dates:

February 7, 1993 - March 13, 1993 Inspectors:

T. P. Johnson, Senior Resident Inspector

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H. K. Lathrop, Resident Inspector. *

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J Inspection Summary:

This inspection report documents inspections to assure public health and safety during day and backshift hours of station activities, including: operations, radiological controls, maintenance and surveillance testing, emergency preparedness, security, engineering/technical support, and safety assessment/quality verification. The Executive Summary delineates the inspection findings_an(j co_nclusions.

9304060142 930325 PDR ADOCK 05000272 G

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EXECUTIVE SUMMARY Salem Inspection Reports 50-272/93-02; 50-311/93-02 Hope Creek Inspection Report 50-354/93-02 February 7, 1993 - March 13, 1993 OPERATIONS (Modules 71707, 93702, 94600)

Salem: The licensee operated the Salem units safely. The licensee appropriately responded to a Unit 1 automatic trip from full power caused by a switch failure in the reactor protection system circuitry. The fire brigade and site protection personnel appropriately responded to an inadvertent Unit 2 carbon dioxide discharge caused by a ventilation high differential pressure condition. The licensee appropriately entered Technical Specification 3.0.3 when both of the Unit 2 turbine first stage impulse pressure instruments became frozen and inoperable. The Salem operating crew displayed good awareness in detecting a Unit 1 overhead annunciator system cathode ray tube display screen failure, and made a conserV'ative system operability determination. The licensee properly responded to a Unit 1 reactor protection system actuation while shutdown, which was caused by operator error. _

Control room operators promptly and effectively responded to a Unit 1 failed automatic level control module for the 13BF 19 feed water regulating valve.

Hope Creek: The licensee operated the Hope Creek unit safely. The issue of electrical power sources relative to an interpretation of Technical Specification 3. 8.1.1, for one of two -

out of service offsite power feeds is unresolved. An open item dealing with a November 1992 reactor water level transient and associated process computer damage was closed.

RADIOLOGICAL CONTROLS (Modules 71707, 93702)

Salem: *Periodic inspector observation of station workers and Radiation Protection personnel noted good implementation of radiological controls and protection program requirements.

The licensee appropriately continued to monitor and evaluate elevated Unit 1 containment particulate radioactivity.

Hope Creek: Periodic inspector observation of station workers and Radiation Protection personnel noted good implementation of radiological controls and protection program requirements. Chemistry and radiation pr:otection personnel demonstrated strong performance during the startup of the hydrogen water chemistry injection system.

MAINTENANCE/SURVEILLANCE (Modules 61726, 62703)

Salem: A Unit 2 out-of-service group bus underfrequency device is a licensee identified, non-cited violation of Technical Specifications. The licensee appropriately responded to a Unit 2 inoperable control rod group manual step counter. Poor communications and inadequate consideration of potential consequences by licensee personnel during a maintenance activity involving the Salem Unit 3 gas turbine resulted in a partial loss of offsite power and an unnecessary plant transient at Unit 1. The licensee systematically investigated and repaired a failed Unit 1 feedwater regulating valve level control module.

Hope Creek: Two unresolved items were closed: the first concerned a safety tagging error during maintenance; and, the second concerned the apparent use of an on-the-spot change to a surveillance procedure which affected acceptance criteria.

Common: The inspector concluded that the licensee has an appropriate program and adequate controls for voluntary Technical. Specification entry to perform maintenance and to conduct testing.

EMERGENCY PREPAREDNESS (Modules 71707, 93702)

The licensee appropriately implemented the emergency response data systems at Salem and Hope Creek. A Hope Creek training drill was an effective training exercise. An open item concerning common site events was closed.

SECURITY (Modules 71707, 93702)

The inspectors determined that the licensee appropriately implemented security program requirements. The inspectors verified the licensee's plans and abilities to respond to a security threat, in view of the recent security-related events involving Three Mile Island and the World Trade Center in New York City.

iii

ENGINEERING/TECHNICAL SUPPORT (Modules 37700, 37828, 71707)

Salem: The inspectors noted that engineering personnel properly prioritized work activities.

System engineering personnel appropriately dispositioned deficient conditions involving leaking Unit 1 pressurizer relief tank rupture discs, and lower than expected Unit 2

containment fan coil unit heat removal capacity. The licensee has an *effective operating experience feedback program as evidenced by timely and appropriate follow-up of a vendor identified potential for an outside containment leak path during accident conditions. The resident inspectors continued to monitor system engl.neering's progress in resolving the continuing problem with boric acid storage tank level indication, that required another Technical Specification 3.0.3 entry during the inspection period. The licensee provided proper attention to a concern in which manual steam line isolations were required following reactor trips. Initial licensee review of a lOCFR Part 21 report regarding potentially inadequate core cooling did not provide sufficient basis for its conclusion; subsequent licensee follow-up and review was prompt.

Hope Creek: The inspectors noted that engineering personnel properly prioritized work activities. A deviation involving the stroke. time acceptance criteria for the residual heat removal system injection valves was adequately addressed by the licensee.

SAFETY ASSESSMENT/QUALITY VERIFICATION (Modules 30702, 40500, 71707, 90712, 92700, 92701, 94702)

Common: The licensee demonstrated an effective self-assessment capability during the conduct of "State of the Station" meetings. The licensee conducted effective Station Operations Review Co111mittee Meetings at Salem and Hope Creek and members displayed a good safety conscious perspective. The licensee demonstrated a proactive and safety conscious approach relative to their preparations for severe weather conditions.

IV

  • TABLE OF CONTENTS EXECUTIVE SUMMARY......................................

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.

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TABLE OF CONTENTS..... ;................ : ~..... -.......... v 1.

SUMMARY OF OPERATIONS............................... 1 1.1 Salem Units 1 and 2.................................. 1 1.2 Hope Creek......... _.............................. 1 1. 3 Common......................................... 1 2.

OPERATIONS......................................... 1 2.1 Inspection Activities......... ~.. *.............. ;....... 1 2.2 Inspection Findings and Significant Plant Events................ 2 2.2.1 Salem... :.................................. 2 2.2.2 Hope Creek.................................. 5 3.

RADIOLOGICAL CONTROLS............... -................ 6 3.1 Inspection Activities.................................. 6 3.2 Inspection Findings.......................... -........ 6 3.2.1 Salem.... *.................................. 6 3.2.2 Hope Creek................................... 7

4.

MAINTENANCE/SURVEILLANCE TESTING................... *.. 7 4.1 Maintenance Inspection Activity.................. -........ 7 4.2 Surveillance Testing Inspection Activity...................... 8 4. 3 Inspection Findings............... _................... 9 4.3.1 Salem...................................... 9 4.3.2 Hope Creek.................. :..............

4.3.3 Common................... _................ - 12 5.

EMERGENCY PREPAREDNESS............................

5.1 Inspection Activity..................................

5.2 Inspection Findings.................................

6.

SECURITY.................................. *........

6.1 Inspection Activity..... ;............................

6.2 Inspection Findings.................................

7.

ENGINEERING/TECHNICAL SUPPORT.......................

7.1 Salem.........................................

7.2 Hope Creek......................................

  • v

Table of Contents (Continued)

8.

SAFETY ASSESSMENT/QUALITY VERIFICATION.*... *...........

8.1 Common _...... *...................................

9.

LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPORTS, AND OPEN ITEM FOLLOW-UP.....................

9.1 LERs and Reports..................................

9.2 Operi Items......................... _.............

10.. EXIT INTERVIEWS/MEETINGS.............,..............

10.1 Resident Exit Meeting.......... *... ~. ~...............

10.2 Specialist Entrance and Exit Meetings......................

10.3 Management Meetings................................. 24

vi

DETAILS 1.

SUM.MARY OF OPERATIONS 1.1 Salem Units 1 and 2 Salem Unit 1 automatically tripped from 100% power on February 16, 1993 due to spurious signal. The unit returned to service on February 21, 1993, and operated for the remainder of the period. Salem Unit 2 operated at power during the period.

1.2 Hope Creek The Hope Creek unit operated at power during the period.

1.3 Common A.

PSE&G Organizational Changes The licensee implemented organizational changes during the period. J. Hagan, the Hope Creek General Manager became the Vice President - Nuclear Operations. S. LaBruna, the Vice President - Nuclear Operations became Vice President - Nuclear Engineering, reestablishing a position last held by T. Crimmins until 1991. R. Hovey, the Hope Creek Operations Manager became the Hope Creek General Manager. R. Swanson, the General Manager - Nuclear Engineering became the General Manager - Quality Assurance and Nuclear Safety Review, replacing L. Reiter, who became Director - Process Improvement.

The licensee stated that the reason for the changes was to provide a broader base of experience and expertise throughout PSE&G's Nuclear Department.

2.

_OPERATIONS 2.1 Inspection Activities The inspectors verified that PSE&G operated the facilities safely and in conformance with regulatory requirements. The inspectors evaluated PSE&G's management control by direct observation of activities, tours of the facilities, interviews and discussions with personnel, independent verification of safety system status and Technical Specification compliance, and review of facility records. The inspectors performed normal and back-shift inspections, including deep back-shift (40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br />) inspections.

2.2 Inspection Findings and Significant Plant Events 2.2.1 Salem A.

Unit 1 Reactor Protection System (RPS) Actuation While Shutdown On January 20, 1993, while in Mode 3 (Hot Standby), an RPS actuation occurred due to operator error. Prior to the actuation, No. 12 steam generator (SG) flow Channel I was out of service for maintenance. The control room operators were in the process of completing a reactor coolant system (RCS) leak rate test. The test required the operators to maintain a constant RCS average temperature. The operators maintained RCS temperature control using the No. 12 SG and the associated atmospheric relief valve. In order to maintain the RCS temperature constant, the control room operator reduced the amount of auxiliary feedwater flow to the No. 12 SG. The operator inadvertently allowed the water level in No. 12 SG to reach its low setpoint (25%). The low water level in the No. 12 SG, in coincidence with a flow channel in the tripped condition, satisfied the RPS trip logic. The reactor trip breakers opened as required in response to the RPS actuation signal. No control rod movement occurred since the reactor was shutdown.

The licensee determined that the root cause of the RPS actuation was personnel error due to inattention to detail. The inspector conducted an independent review of this event. The inspector also noted weak pre-planning for the RCS leak rate surveillance test. In particular, with No. 12 flow channel out of service, a different SG should have been selected for temperature control as some SG level oscillations would have been expected on the controlling SG. The licensee counselled the operator involved, with emphasis on attention to detail during control room activities. Licensee management also counselled the shift supervisor, with emphasis on command and control of control room activities. The inspector concluded that the licensee's response to this event was appropriate.

B.

Unit 2 Technical Specification (TS) 3.0.3 Entry Due to Loss of Turb~ne First Stage hnpulse Pressures (PT-505 and PT-506)

On February 6, 1993, the licensee entered TS 3.0.3 when both PT-505 and 506 became inoperable apparently due to cold ambient temperatures (l5°F). The licensee concluded that instrument sensing line freeze protection was less than adequate due to degraded insulation and heat tracing wiring. These devices, located in an enclosure on the open air turbine deck, were inoperable for less than five minutes as the licensee thawed the sensing lines by modifying turbine building ventilation. Additional corrective actions included instructions in the operations night order book involving monitoring of the system, repair of the freeze protection systems, a check of the Unit 1 configuration and revisions to the winter operation procedure.

The inspector reviewed this event by holding discussions with licensee personnel and

. reviewing the Licensee Event Report (LER). The inspector concluded that the licensee appropriately addressed this issue, and closed this LER.

C..

Partial Loss of Unit 1 Overhead Annunciator System At 3:40 p.m. on February 8, 1993, a Unit 1 control room operator noted that the time signal on the overhead annunciator (OHA) system cathode ray tube (CRT) screen had apparently stopped updating at*3:26 p.m. that day. This CRT displays and provides amplifying information for the alarms received by the OHA system. Sensitive to the recent problems that have occurred with the Salem OHA systems (see NRC Inspection 50-272&311/92-81),

the operators checked the OHA system printer to verify that all alarms received by the system had been properly passed to the overhead window panels. Unfortunately, at the time the CRT failed, the printer had been out of paper, and the operators could not immediately verify OHA system operability. Consequently, the operating crew declared the system inoperable, notified the NRC, and initiated corrective actions. Within ten minutes of the discovery of the event, the operators replaced the printer paper and verified that, except for the CRT, the OHA system was and had been operating properly. The responsible Salem system engineer responded to the control room and supervised the resetting of the CRT, restoring it to a functioning status.

  • The licensee conducted a subsequent investigation into the CRT failure, and the system engineer determined the cause to be an intermittent failure in the push-type connector that provided the CRT's connection to the OHA system computer. The licensee replaced this connector with a solder-type connector, and no further problems occurred through the remainder of the inspection period. Based on the results of their investigation, PSE&G conducted that the problem had not affected the operability of the OHA system and, on February 9, retra~ted the report they had made to the NRC concerning the loss of assessment capability.

The licensee informed the resident inspector of the event, and the inspector monitored the licensee's investigation and discussed the event with the system engineer. The inspector determined that the control room operators displayed good awareness in detecting the CRT failure, the operating crew made a conservative operability call and notification to the NRC, and that the licensee appropriately responded to the event.

D.

Unit 1 Automatic Reactor Trip Due to Equipment Failure On February 16, 1993, Unit 1 automatically tripped from full power due to a spurious over-temperature differential temperature (OTDT) signal. Prior to the trip, technicians placed the loop No. 13 OTDT bistables in the tripped position due to calibration of the associated power range nuclear instrumentation. Subsequently, a spike on loop No. 11 OTDT instrumentation occurred, which satisfied the OTDT reactor trip coincidence (two out of four) and resulted in the reactor trip.

.,

Safety systems responded normally to the trip. All control rods fully inserted, and the auxiliary feedwater automatically initiated and recovered steam generator water levels.

Control room operators entered emergency operating procedures (EOPs) immediately following the reactor trip. Control room operators manually initiated a steam line isolation to prevent an excessive unit cooldown (See Section 7.1.E) as prescribed by EOPs. *The licensee reported this event to the NRC per the reporting requirements of CFR 50. 72.

The unit remained in Mode 3 (Hot Standby), at normal operating pressure and temperature following the trip. During that time, the licensee completed troubleshooting activities to determine the root cause of the OTDT instrument spike. The investigation identified a failed gain selector switch in a Hagan module that provides an a.Xia! flux difference input to the OTDT protecti_on circuit.

  • The licensee's follow-up and review of the reactor trip included completing the post-trip review per procedure AD-16. In addition, the licensee formed a Significant Event Review Team (SERT) to independently review and evaluate the reactor trip. The licensee concluded that the root cause of the reactor trip was equipment failure. The Station Operations Review Committee (SORC) reviewed the completed AD-16 procedure on February 19, 1993, and subsequently authorized restart of the unit. The reactor achieved criticality on February 20, 1993.

The inspector monitored the licensee's maintenance troubleshooting and other event follow-up activities, and independently evaluated the reactor trip response. The inspector also attended the February 19 SORC meeting. The meeting included frank and thorough discussions regarding unit response and root cause of the event. The inspector concluded that the SORC review was excellent. The inspector concluded that the licensee response to the trip, including operator performance, post trip (AD-16), review SERT and troubleshooting activities, were _thorough and well performed.

E.

Unit 2 Carbon Dioxide (Cardox) Discharge An inadvertent cardox discharge occurred in the Salem Unit 2 No. 22 diesel fuel oil storage tank room on February 20, 1993, at 1 :20 p.m. The licensee's fire brigade responded to a

.control room alarm and a local report from a roving fire watch. The fire brigade determined that there was no fire, reset the cardox system, and restored the fire detector/suppression system per procedure MlO-SST-021-2. The fire brigade also ventilated the room to remove the carbon dioxide gas. The control room operators initiated an emergency notification system (ENS) call at 3:38 p.m. per 10CFR50. 72(b)(2)(vi) due to an offsite notification.

The licensee's review of this inadvertent cardox discharge included a fire department and operations incident report. The licensee concluded that the discharge resulted from a room ventilation high differential pressure that actuated heat detector 87-1. This fire (heat)

detector then initiated the cardox. logic. The licensee determined that the current type of heat detectors is susceptible to excessive differential pres.sures. Consequently, the licensee is pursuing replacement detectors that would function reliably in the environment.

The inspector reviewed the ENS report, both incident reports, the fire detector and suppression restoration procedure, and personnel statements. The inspectOr also discussed this event with Salem operations and fire protection management personnel. The inspector concluded that the licensee responded appropriately to this event.

2.2.2 Hope Creek A.

Electrical Power Sources *

During the routine morning tour on March 11, 1993, the inspector noted that one of two offsite power feeds to the "D" 4160 VAC vital bus was out of service (breaker 52-40401).

The other offsite source (breaker 52-40408) provided power to the "D" bus. The licensee removed breaker 52-40401 frqm service at 6:00 a.m. to troubleshoot a charging motor problem. Subsequent checks could not find any problems. The Operations Department successfully tested the "D" emergency diesel generator (EDG) at 2:00 a.m. that morning during its scheduled monthly surveillance. The inspector questioned why the licensee had not entered Technical Specification Action Statement (TSAS) 3.8.1.1.a. This TS requires two offsite circuits between the grid and the onsite lE distribution system.

Licensee personnel stated that they met the TS and therefore had not entered the TSAS. The licensee's basis for this conclusion was established on their confirmation of the following:

(1) operability of both offsite sources from the grid through transformers AX501 and BX501, (2) availability of power to the vital bmes (three of four are required for the design basis accident-FSAR Section 8.1.2), (3) operability of all four vital buses and EDGs, and (4)

satisfactory completion of the requirements of surveillance procedure HC.OP-ST.ZZ-OOOl(Q)

regarding the operability of electrical power sources. The licensee intended to enter TSAS 3.8.1.1.a, if another breaker supply to any other vital bus failed. Such action would require a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> time limit with periodic testing of all EDGs and verification of electrical power lineups. The licensee returned the breaker (52-40401) to service and realigned the "D" vital bus by 11 :00 a.m.

After further discussions with plant management, the inspector contacted NRC Region I and NRR for further interpretation. The inspector also noted that the licensee did not have any formal TS interpretations for this issue. Accordingly, interpretation of TS 3.8.1.1.a, relative to a single vital bus electrical feed out of service is unresolved pending further NRC and licensee review (URI 50-354/93-02-01).

B.

Open Item Follow-up (Closed) Unresolved Item 50-354/92-18-02. Reactor Water Level and Pressure Transient.

In November 1992, a watt transducer in the "A" reactor recirculation motor generator (MG)

set failed, resulting in spurious control room annunciations/indications, reactor water level high and low level alarms, and process computer damage. The licensee performed a comprehensive review of the *event, as documented in Incident Report 92-181 and an internal

. memorandum dated December 22, 1992. The licensee's.investigation concluded root cause to be random failure of the 120 VAC power supply for the "A" MG set watt transducer.

Except for the reactor water level changes, all other control room indications associated with this event were spurious. Also, the licensee's investigation demonstrated that no solar magnetic disturbance had occurred. The inspector reviewed the licensees's findings and conclusions, determinin,g that the licensee's analysis and corrective actions were both thorough and appropriate, and therefore closed* the item.

. 3..

RADIOLOGICAL CONTROLS 3.1 Inspection Activities The inspector verified on a periodic basis PSE&G's conformance with the radiological protection program.

3.2 Inspection Findings 3.2.1 *Salem A.

Unit 1 Containment Particulate Radioactivity As discussed in NRC Inspections 50-272/93-01, 92-19 and 92-13, the containment particulate radiation monitor (lRl lA) continues to indicate a higher level than normal. Because of this, three containment ventilation isoia:tions C?Ccurred during the period (February 24 and 28, March 1, 1993). The licensee identified small leaks on the pressurizer relief tank (Section*

7.1.A). Reactor coolant system unidentified leak rate remained normal.

On March 8, 1993, the licensee removed the isolation function of the lRl lA monitor by installing an_electrical jumper. The SORC approved an associated safety evaluation on March 4, 1993. Technical Specification (TS) amendment No. 79 (1987) previously authorized this removal, however, at that time the licensee elected to maintain the isolation *

function operable. TSs require the isolation function to be operable in Mode 6 (Refueling)

only. The licensee modified the appropriate station procedures.

The inspector confirmed licensee actions, monitored the lRl lA readings, reviewed the safety *

evaluation, TS, the licensee event report and incident reports, reviewed chemistry sample results, and discussed this item with appropriate licensee personnel. The inspector concluded that licensee follow-up actions were appropriate and will continue to monitor the

.

.

effectiveness of those actions in identifying the cause(s) of and corrective actions for the elevated lRl lA readings.

3~2.2 Hope Creek A.

Hydrogen Water Chemistry Injection (HWCI) System Startup The lic~nsee initiated the HWCI system on February.15, 1993. Prior to the hydrogen/oxygen fojections, the chemistry test manager and test engineers conducted a pre-evolution briefing in the control room. The licensee started up HWCI per design change package (DCP) 4HC-0242 package No. 5 and chemistry procedures HC.CH-SO.AX-OOOl(Z)

and 0005(Z). This included hydrogen injection into the feedwater system via the secondary condensate pumps, and oxygen injection into both the condensate system and the offgas recombiner.

The inspector reviewed the DCPs, the operating procedures, the safety evaluation, and the system drawings. The inspector accompanied chemistry, system engineering and maintenance personnel on an. HWCI system walkdown prior to system startup. The inspector also observed the pre-evolution briefing, examined system operation in the field and questioned control room *operators on their HWCI system knowledge. The inspector noted*

that the licensee conducted a comprehensive briefing, personnel were very knowledgeable regarding HWCI system operation, and radiation protection personnel were prepared for the expected increase in. general area radiation levels.

4.

MAINTENANCE/SURVEILLANCE TESTING 4.1 Maintenance Inspection Activity The inspectors observed selected maintenance activities on safety-related equipment to ascertain that the licensee conducted these activities in accordance with approved procedures, Technical Specifications, and appropriate industrial codes and standards.

The inspector observed portions of the following activities:

Salem 1 Work Order(WO), Procedure, or Design Change Package CDCP) Description Various lC and lB emergency diesel generator (EDG)

Salem 1 SC.IC-GP.ZZ-0006(Q)

Hope Creek WO 930501040 Hope Creek WO - Various

13BF19 (feedwater regulating valve) automatic control Boric acid pump piping and gauge modifications 23 charging pump Fuel Pool cooling valves and pump maintenance Service water pump intake bay inspection and desilting The maintenance activities inspected were effective with respect to meeting the safety objectives of the maintenance program.

4.2 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 licensee performed surveillance tests in accordance with Technical Specifications, approved procedures; and NRC regulations.

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

Salem 2 Salem 1 Salem 1 Hope Creek Hope Creek Procedure No.

S2. OP-PT~ SW-0024(Q)

Sl.OP-ST.DG-OOOl(Q)

SP(0)4.4.6.2d HC.MD-GP.ZZ-0224(Q)

OP-IS.EA-002 24 Containment Fan Coil Unit Performance Test IA EDG Surveillance Test Reactor Coolant System - Water Inventory Balance Fuel Pool Cooling Valve 1EC-HV-4689B Actuator Testing

"B" Service Water Pump 92 Day Inservice Test

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

4.3 Inspection Findings 4.3.1 Salem A.

Unit 2 2H Group Bus Underfrequency (UF) Protection During surveillance testing on January 12, 1993, the licensee discovered that the 2H bus group bl}s UF protection had been out of service since the previous test on December 9, 1992, apparently due to a technician's personnel error. The technician failed to reclose the UF relay knife switch after testing. This UF device is one of four channels for reactor coolant pump (RCP) bus inputs into the reactor protection system (RPS). The remaining three channels remained operable during this period. The licensee's review also noted that the redundant RPS functions (undervoltage and RCP low flow) remained operable. Technical Specification (TS) Table 3.3.1.1 requires operability of these UF devices.

  • The inspector reviewed the LER (No. 93-02) and discussed it with the appropriate licensee personnel. The inspector concluded that this is a licensee identified violation of TS and is not being cited because the criteria in section VII.B of the Enforcement Policy were satisfied.

The licensee's corrective actionsincluded disciplinary acti~n, eventreview by maintenance department personnel and procedural enhancements to include independent verification of the test switches. The inspector concluded that the licensee's actions were appropriate.

B.

Unit 2 Inoperable Group Demand Step Counter On January 20, 1993, the licensee reported an engineered safety feature (ESF) actuation while in Mode 3 (Hot Standby). Specifically, during surveillance testing, control rods were manually inserted and the reactor trip breakers were manually opened as a result of the group demand counters failing to properly indicate control rod withdrawal demand. Thecontrol rods were the four shutdown rods from shutdown bank "C". The rods had been withdrawn about five steps. The technicians determined that the group demand counter access door was not fully shut, preventing the step counter clutch from engaging.

On February 16, 1993, the licensee retracted the report to the NRC on the basis of NUREG 1022, "Licensee Event Report System," which states that a preplanned sequence documented in a procedure is not reportable. In addition, Technical Specification 3.1.3.2.2 prescribes the actions taken by the licensee.

The inspector reviewed the licensee's actions and NRC reporting guidance, and consulted the NRC project manager. The inspector concluded that the licensee appropriately responded to

. and evaluated this event.

c.

Unit 3 Output Breaker Trip and Subsequent Partial Loss of Offsite Power Salem Unit 3 is a gas turbine-generator (GT) system connected to the Salem 13 KV ring bus, which is used by PSE&G to augment their generating capacity at times of peak load.

PSE&G had disconnected the unit from the electrical distribution system in September 1992 in order to conduct a five month overhaul of the unit. On February 21, 1993, the Unit 2 Nuclear Shift Supervisor (NSS) authorized the release of the safety tags on the GT output breaker in order to conduct post-maintenance and surveillance testing of the unit. Early in the afternoon, the NSS, the system engineer (SE) and an equipment operator (EO) began making preparations to conduct testing, and the EO racked-in the breaker. Neither the NSS rtor the SE heard the closing springs change as expected, and the NSS directed the EO to rack-out the breaker in order to investigate the perceived problem. The EO was unable to rack-out the breaker, and the NSS summoned a maintenance supervisor (MS) to assist. The MS suspected a problem with the charging springs and believed the only way to rack-out the breaker was to have it in the closed position. Subsequently, he directed the EO to close the breaker. When the EO manually closed the racked-in breaker (without the GT operating at normal voltage) the breaker failure relay and the generator reverse-power relay actuated.

Consequently, the GT output breaker and other downstream breakers (associated with the relay protection scheme) tripped open.

At the time of this event, Unit 1 was critical (Mode 2) and power level was lE-8 amp.s in the intermediate range, following the reactor trip of February 16, 1993 (See Section 2.2.1.A of this report). The relay protection scheme opened the breakers supplying the station power transformer (SPT) which powered one side of the Unit 1 and Unit 2 4KV vital busses. Since Unit 1 was not yet_on line, the group busses fast-transferred to the other available SPT as designed, and no safety related loads were lost at either unit. When the Unit 1 group busses were de-energized, however, the No. 13 and 14 RCPs were also de-energized.

Consequently, the unit operators were required to make Unit 1 subcritical and open the reactor trip breakers. Following an inspection of the GT and the relays which tripped, the licensee restored the switchyard to normal. Upon conclusion of their component inspection and testing, the licensee successfully completed the originally planned test of the GT.

Due to the significance of the partial loss of offsite power event and the multi-disciplinary involvement in the GT work, the General Manager - Salem Operations chartered a Significant Event Response Team (SERT) to investigate the event and determine its root causes. The SERT determined the event to be the result of poor communication between the involved parties and their insufficient knowledge of the breaker failure relaying scheme. The EO had apparently not informed the NSS and SE of status of the breaker closing springs, and none of those three personnel had informed the MS that the GT was electrically connected to the Salem electrical distribution system when he directed the breaker to be closed. The SERT also found that neither the operating crew nor the personnel involved with the GT test had assumed the initiative to determine the consequences of closing the GT output breaker.

l

The licensee informed the resident staff of the event the day after it occurred, and the inspector reviewed the event and its consequences and monitored the performance of the SERT. The inspector concluded that all safety-related equipment had properly performed and the safety significance of the event was thereby mitigated.' The inspector also determined pre-event communications between the involved personnel had been poor and that the licensee had not been properly sensitive to the possible consequences of the GT testing, considering the more vulnerable position of Unit 1 because it was not on-line at the time of the testing. The event resulted in an unnecessary transient at Unit 1 when the RCPs tripped and the unit had to be taken subcritical.

The licensee initiated several short-term corrective actions to preclude the recurrence of this event; among them was the placing of caution tags on the GT output breaker to prevent the closing of the breaker without the generator operating at normal speed and to prevent the racking-in of the breaker with the closing springs charged. The SERT also developed a number of longer term recommendations, including procedural controls and preventive maintenance changes for the breaker, that the licensee has assigned to the responsible Salem department for tracking and completion. The inspector reviewed the SERT's report and the licensee's proposed corrective actions, and determined that PSE&G's post-event investigation and response was well conducted and effective.

D.

Unit 1 Feedwater Regulating Valve Controller Failure On March 11, 1993, during steady state 100% power operation, one of the four feedwater regulating valves (No. 13BF19) failed to its fully opened position. The valve had previously been functioning normally in automatic and properly controlling steam generator (SG) water level. Control room operators responded immediately by placing the controller for 13BF19 in manual. Water level in No. 13 SG increased to about 55% (normal level is 44%). The SG high water level turbine trip and feed water isolation occurs at 67 %.

On March 12, the licensee developed a troubleshooting plan to investigate the cause of the automatic control problem for 13BF19. Maintenance personnel reviewed plant drawings and identified two Hagan modules to be the likely cause of the problem. The modules were associated with the SG level error circuit and the flow error circuit. A systematic troubleshooting plan was developed by I&C maintenance, system engineering and operations personnel. The-technicians developed the detailed troubleshooting plan per the requirements of maintenance procedure No. SC.IC-GP.ZZ-0006(Q), "Controls Equipment -

Troubleshooting". The troubleshooting and repair activities were completed on March 12.

The licensee found a defective level error module circuit card, and subsequently repaired, tested and reinstalled the Hagan module. The inspector concluded that operator response to the event was excellent in that a more severe plant transient and/or reactor trip was averted.

The inspector also concluded that the troubleshooting activities were well-planned and executed.

4.3.2 Hope Creek A.

Open Item Follow-up (Closed) Unresolved Item (50-354/92-04-01). Safety tagging error during hydraulic control unit (HCU) 'maintenance. While performing corrective maintenance on HCU No. 46-39 on March 24, 1992, contaminate<l water sprayed an area of the reactor building when a solenoid valve was disassembled for repair. The nuclear safety aspect of this event was minimal.

However, the potential for personnel injury/contamination and equipment damage was significant. The inspector reviewed the licensee's root cause investigation and corrective actions. The supervisors directly involved were counseled on work control practices involving tagout review and personnel protection. Work responsibilities were reviewed with all first line and senfor supervisors in the maintenance and chemistry departments. The inspector noted that the station quality assurance (SQA) group had performed an independent

. ~assessment of this event. The licensee had incorporated several of SQA's recommendations.

The inspector concluded that the licensee's actions were appropriate and appeared effective since no similar incidents have occurred in the past year, and therefore closed the item.

(Closed) Unresolved Item (50-354/92-06-02). Apparent inappropriate use of an on-the-spot change (OTSC) to delete acceptance criteria. In May 1992, during the performance of a surveillance on the torus to drywell vacuum breakers, the licensee made several changes to the surveillance procedure usi,ng an OTSC. Upon reviewing the changes, the inspector observed that the licensee had apparently deleted test acceptance criteria, which is not permitted by licensee procedures. The licensee reviewed this incident and determined that a clerical error had been made during the mark up of the procedure with the desired changes.

The error was not detected during supervisory review of the OTSC prior to implementation.

The licensee's corrective actions included counseling of the reviewing personnel, procedural clarifications dealing with OTSC usage and reviewing this event with the operations support staff. The inspector concluded that these actions were appropriate and appeared effective in preventing similar events, and therefore closed the item.

4.3.3 Common A.

Technical Specification Action Statement (TSAS) Voluntary Entry to Conduct Maintenance During the inspection period, the licensee made multiple entries into TSASs to perform preventive and corrective maintenance, and to conduct performance testing. The inspector reviewed two such instances as follows:

Salem performance testing and corrective maintenance for several containment fan coil units (CFCUs).

Hope Creek silt removal of the four service water (SW) pump intake bays.

Based on questions regarding the licensee's program, the iilspectors held a working level meeting onsite on February 25, 1993. The NRC inspectors, the NRC Section Chief and Project Managers, and PSE&G Salem and Hope Creek personnel attended. PSE&G discussed their program and the specifics associated with the Salem CFCU performance testing and the Hope Creek SW pump intake bay silt removal. The licensee stated that it was their policy to remove safety systems from service to perform maintenance on~y if management was assured that a "net safety gain" could be achieved. The licensee demonstrated that these particular cases represented non-intrusive work and was justifiable since the maintenance and testing provided a net safety benefit that is realized in the enhanced assurance of system reliability and function. Attachment 1 is the licensee's handout used at this meeting.

The inspector concluded that the licensee has an appropriate program and controls for voluntary TSAS entry to perform maintenance and to conduct testing.

5.

EMERGENCY PREPAREDNESS 5.1 Inspection Activity The inspector reviewed PSE&G's conformance with 10CFR50.47 regarding implementation of the emergency plan and procedures. In addition, the inspector reviewed licensee ~vent notifications and reporting requirements per 10CFR50.72 and 73.

5.2 Inspection Findings A.

Emergency Respo-nse Data System (ERDS)

During the inspection period, PSE&G implemented the ERDS for both Salem 1 and 2, and Hope Creek. _This system provides on-line, real time plant data transmission to the NRC.

Emergency planning personnel conducted training for operations personnel and modified the appropriate implementing procedures.

The inspector observed selected training sessions, reviewed the revised procedures and questioned operators on the ERDS. The inspector concluded that the licensee appropriately implemented the ERDS at Salem and Hope Creek.

B.

Hope Creek Training Drill The emergency preparedness (EP) organization conducted a training drill at Hope Creek on February 25, 1993. The licensee developed a scenario that activated all EP facilities, and designated drill players and evaluators.

The inspector observed drill performance from most BP facilities. The inspector determined that the drill was an effective training evolution and licensee performance was good.

C.

Open Item Follow-up (Closed) Unresolved Item (50-272 and 311/92-01-01, 50-354/92-01-02). Common site events and emergency action levels (EALs). Both the Salem and Hope Creek EALs for low and high river level are conservative but different. The licensee chose this difference to preclude simultaneous event classification and notifications that could confuse the offsite agencies. The licensee considered one station declaring a common site event. However, the licensee concluded that due to current commitments to the States of New Jersey and Delaware, this would be awkward; the States and,the NRC would only get specific information from one site when both sites are in an emergency. This would also result in having an Emergency Coordinator at one station trying to represent both his station and also the other station on which he is not qualified. The current direction is to allow both stations to be responsible for their own classifications and notifications.

The inspector reviewed this issue and concluded that the licensee appropriately addressed this issue of common site events. The inspector also noted that current NUMARC guidance about EALs is being reviewed that may modify this response.

6.

SECURITY 6.1 Inspection Activity PSE&G verified regularly the conformance with the security program, including the adequacy of staffing, entry control, alarm stations, and physical boundaries.

6.2 Inspection Findings A.

PSE&G Response to a Potential Land Vehicle Bomb Event Because of the bombing that occurred at the World Trade Center in New York City on February 26, 1993, and the intrusion of the Three Mile Island protected area that had occurred on February 7, 1993, the NRC resident staff reviewed the licensee's response to the latter event and their Safeguards Contingency Plan (SCP), which deals with land vehicle bomb events. Through discussions with the PSE&G Site Security and Emergency Preparedness Managers, the inspectors determined that the Deputy Director of the New Jersey State Police Office of Emergency Management had informed PSE&G of the World Trade Center bombing within hours of the event and that PSE&G had implemented additional.

security measures through the weekend following the event.

The inspectors additionally reviewed all applicable SCPs and found that the licensee's security plan includes a land vehicle bomb event response specifically developed in response to NRC Generic Letter 89-07, "Power Reactor Safeguards Contingency Planning for Surface Vehicle Bombs." Other station SCPs are established for a range of other security. threats.

The inspectors concluded that PSE&G had appropriately responded to the notifications of the above cited events, and has the SCPs in place to respond adequat~ly to such events.

7.

ENGINEERING/TECHNICAL SUPPORT 7.1 Salem A.

Unit 1 Pressurizer Relief Tank (PRT) Rupture Disc Leakage During the Unit 1 forced outage (Section 2.2.1.B), licensee inservice inspection (ISI)

personnel examined reactor coolant and primary systems' components in the containment for potential leaks. This was in response to higher than expected containment particulate radiation monitor indications (See Section 3.2.1.A of this report and NRC Inspections 50-272/93-01, and 92-13 and 92-19). The ISI personnel initially checked for leaks by performing visual inspections. When this revealed no abnormalities, the ISI personnel then used a more sensitive technique to check for leakage. They identified five pinhole leaks from one of two Unit 1 PRT rupture discs. The licensee identified the leakage quantity to be minor seepage.

The licensee initiated an incident report, a deficiency report (DR) and a work order (WO 930217211) to document and evaluate these pinhole leaks. System Engineering personnel performed a 10CFR50.59 review and safety evaluation of this condition. Based on the PRT and rupture disc functions as described in the UFSAR, and the fact that the rupture disc is a non-code component, the licensee concluded that leakage did not impact the ability of the rupture disc to perform its function. The licens~ intends to replace the rupture disc during the next outage of sufficient duration, but no later than the fall 1993 refueling outage (lRl l).

The inspector reviewed the appropriate documentation, including the incident and deficiency reports, the WO, the safety evaluation, PRT drawings and system descriptions. In addition, the inspector discussed this issue with licensee engineering and operations personnel, and with NRC specialists. The inspector questioned the licensee's plans to monitor periodically for rupture disc degradation. The licensee verified that the other Unit 1 PRT rupture disc was intact, and were considering inspections of the two Unit 2 PRT rupture discs. The licensee initiated action to periodically verify the radiation monit<;,lr indications, and periodically monitor the leaking disc until replacement. The inspector had no further questions at this time, and concluded that the licensee appropriately evaluated and dispositioned this deficient condition.

-B.

Unit 2 No. 24 Containment Fan Coil Unit (CFCU) Performance Te5ting During the inspection period, the licensee conducted thermal performance tests for the Unit 2 CFCUs per NRC Generic Letter 89-13. Tests results for the 24 CFCU indicated a heat removal capacity of 65.1 million BTU/hr. This was below the UFSAR minimum acceptable of 81 million BTU/hr. at a water inlet temperature (Delaware River) of 90°F. Based on this result, the licensee initiated deficiency report (DR) No. SMD 93-18.

The licensee initiated an evaluation of this condition and performed a 10CFR50.59 safety evaluation. The safety evaluation concluded that interim use of the 24 CFCU was acceptable since the Delaware River was at or below 43 °F. (At the end of the inspection period the River temperature was 35°F.) If the River exceeds this value (43 °F), the licensee intends to declare 24 CFCU inoperable and enter to Technical Specification Action Statement 3.6.2.3.

Further, the 24 CFCU is scheduled for cleaning during the upcoming Unit 2 refueling outage (2R7) scheduled to begin March 20, 1993.

The inspector reviewed the DR and the safety evaluation, and discussed it with station engineering and management personnel. The inspector noted that the Station Operations Review Committee (SORC) approved the safety evaluation at SORC Meeting 93-17. The inspector had no further questions at this time, and concluded that the licensee appropriately dispositioned this issue.

C.

Volume Control Tank (VCT) Check Valve Leakage during Accident Conditions NRC Region I informed the inspector of a potential release path during a loss of coolant accident (LOCA) identified at a similar Westinghouse PWR. The VCT check valve could leak during a small break LOCA recirculation phase. This would then set up a release path from the safety injection (SI) system to outside containment, causing the VCT and seal water heat exchanger relief valves to lift. Westinghouse communicated this problem to PWRs in a letter (NSAL-92-012) in December 1992.

PSE&G received the letter and followed up this issue per NC.NA-AP.ZZ-0054(Q),

"Operating Experience Feedback Program." The licensee initiated action tracking form number PSE-92-708. * The Salem inservice testing (IST) engineer reviewed the current program and concluded that the check valves (1CV42 nd 2CV42) are included in the approved IST program. Periodic surveillance testing is performed and each valve is within its allowed test interval. Thus, the licensee closed the issue on February 16, 1993.

The inspector reviewed the P&IDs for the SI system and concluded that Salem does have a similar piping arrangement._ Further, the inspector reviewed the IST program, including 1(2)CV42 valve test sheets and surveillance test records. The inspector concluded that these check valves are periodically tested, and that the licensee appropriately responded to this issue in_ a timely manner.

D.

lOCFR Part 21 Report Review - Potential Inadequate Core Cooling On January 8, 1993, Westinghouse Electric Corporation submitted to the NRC a lOCFR Part 21 notification that potentially impacted Salem Units 1 and 2. The issue concerned the licensee's ability to supply adequate flow to the reactor coolant system (RCS) to maintain long term cooling. Westinghouse postulated a single valve failure (valves 1RH26 and 2RH26 for Salem) such that its failure to open would prevent a successful transfer to hot leg recirculation via the residual heat removal (RHR) system. That failure, in combination with terminating cold leg injection from the RHR system, could potentially result in insufficient RCS flow following a postulated accident.

The inspector verified that the licensee received the Part 21 report from Westinghouse, and had reviewed the information relative to the potential impact on the Salem \\!nits. The licensee closed the assigned item on March 1, 1993, with no short term actions planned; only longer term emergency operating procedure enhancements. Inspector review of the item identified that there was not a sufficient technical quantified basis for the licensee's conclusion. Specifically, assuming an RH26 valve failure to open and a subsequent isolation of cold leg injection from the RHR system (SJ49 valves), it was not evident that sufficient flow could be provided to the RCS via other safety injection subsystems. The inspector communicated this concern to the licensee.

On March 11, 1993, the licensee completed preliminary calculations in response to the inspector's concerns, assuming a failure of RH26 and the subsequent closure of the two SJ49 valves. The preliminary calculations demonstrated that the remaining, existing flow to the RCS would be sufficient to ensure adequate core cooling.

The inspector concluded that the license..~'s initial review of the Part 21 did not provide sufficient basis for the conclusion. The inspector determined, however, that the licensee.

promptly responded to the noted concerns. This item is unresolved pending licensee completion of the calculations and subsequent review by the NRC (URI 50-272&311/93-02-01).

E.

Manual Steam Line Isolations Following Reactor Trips Following the February 16, 1993, Salem Unit 1 reactor trip, plant operators manually initiated a main steam isolation (MSI) in accordance with emergency operating procedures (EOPs) to prevent an excessive primary system cooldown. The inspector noted that control room operators frequently initiate manual MSis following reactor trips.

NRC Combined Inspection 90-19 documented an MSI following June 1990 reactor trip. The licensee suspected that the reason for the excessive cooldowns was high auxiliary feedwater (AFW) system flow rates, i.e., the flow control valves were set such that actual flow greatly exceeded that required design specifications. The NRC report documented that licensee efforts were continuing to determine a permanent resolution of the concern. One action

taken was a change to Operations Procedure AD-44, "EOP Program Maintenance," which allowed control room operators to adjust (reduce) AFW flow to design requirements after the EOP immediate action steps have been completed, but before EOPs directed AFW flow adjustment. However, in responding to actual reactor trips, control room operators have rarely reduced AFW fiow before the existing EOP step. Consequently, operators typically initiate MSis due to reactor coolant system (RCS) cooldown following reactor trips. Further review of this concern by the inspector identified that heat loss from the steam lines throughout the turbine building atmosphere also may contribute to the rapid RCS cooldown.

The licensee is planning to implement a design change on the AFW system flow control valves to modify the valve trim. That change is expected to reduce the AFW flow due to a separate design basi~ AFW system concern (See NRC Inspection 92-18). The modification is expected to provide some benefit to the excessive RCS cooldown concern. In addition, while reviewing the February 16, 1993 reactor trip, the Station Operations Review Committee (SORC) issued an open item to further evaluate and address the required MSI concern. The inspector concluded that the SORC provided sufficient attention to the issue.

F.

Unit 1 Technical Specification 3.0.3 Entry Due to.Failed Boric Acid Storage Tank Level Indication On March 6, 1993, while the No. 11 boric acid storage tank (BAST) was cleared and tagged for work to be done on the N(). 11 boric acid transfer pump, the level indication on the No.

12 BAST failed at 00:50 a.m. The Action requirements of Technical Specification (TS) 3.3.3.7 permits one BAST level indication to be operable provided the remaining BAST can

-

.

satisfy the level, boron concentration and temperature requirements of TS 3.1.2.8.a. Since the No. 11 BAST was out of service when the No. 12 BAST level indication failed, the licensee entered TS 3.0.3 and prepared to shut down Unit 1.

Unit 1 operators identified the problem with the No. 12 BAST to be boron crystallization in the tank's level instrumentation tubing and subsequently increased the blowdown rate of the associated bubbler in the tank. The corrective action restored level indication in the No. 12 BAST, and the Unit 1 operating crew consequently exited TS 3.0.'3, averting the unit shutdown.

The inspector noted a recurrence of previous problems (See NRC Inspection 50-272&311/91-01). Salem system engineering had addressed the problem of boron crystallization by decreasing the bubbler nitrogen flow rate, which raised the local BAST temperature, thus deterring the boron crystallization. System engineering is still pursuing a longer-term resolution of the problem. The licensee notified the NRC resident inspector of the TS 3.0.3 entry, and the inspector determined that the Unit 1 operators had properly recognized and responded to the event. The inspector will continue to monitor system engineering's progress in resolving the issue, including LER submittal.

G.

Open Item Follow-up (Closed) Unresolved Item (50-272/93-01-01). Unii 1 Startup and Estimated Critical Position (ECP). The licensee completed their review and incident report (93-58) for an ECP error that occurred on a Unit 1 startup on January 21, 1993. The licensee determined root cause to be lack of guidance in procedure S 1. RE-RA. ZZ-0001 ( Q),

11 ECP, 11 regarding the selection of the previous reactor critical condition.* A contributing factor was the Unit 1 power.

history, which included a transient condition. Corrective actions included ECP procedure revisions and recalculation of the ECP.

The inspector reviewed the incident report and discussed it with reactor engineering personnel. The inspector concluded that the licensee appropriately addressed this issue, and therefore closed the unresolved item.

7.2 Hope Creek A.

Open Item Follow-up (Closed) Deviation (50-354/92-03-03). Low pressure coolant injection (LPCI) injection valve stroke time criteria. During an inspection of surveillance testing on three safety-related systems in April 1992, the inspector noted a difference between the maximum opening time for the LPCI injection valves as stated in the updated final safety analysis report (UFSAR)

and a number of LPCI surveillance procedures. The inspector concluded that this was an isolated instance. The licensee committed to reviewing other surveillance procedures with UFSAR limits on system performance to assure conformity with UFSAR requirements. The inspector reviewed the licensee's corrective actions, as detailed in their response to the notice of deviation dated July 17, 1992. The inspector verified that the appropriate opening time of 24 seconds had been incorporated in procedures HC.OP-ST.BC-0004, 0005, 0006, and 0007.

The inspector noted that the licensee had also reviewed the applicable surveillance procedures for the core spray and high pressure coolant injection (HPCI) systems to assure their conformance to design, Technical Specifications and UFSAR requirements. The licensee found no discrepancies during this review. Based on the foregoing, the inspector concluded that the licensee had adequately met their commitments regarding this issue and had acceptably incorporated the necessary changes in the surveillance procedure. This deviation

  • is therefore closed.*

8.

SAFETY ASSESSMENT/QUALITY VERIFICATION 8.1 Common A.

State of the Station Meetings During the inspection period, both the Hope Creek and Salem General Managers conducted

"State of the Station" meetings with all plant personnel. At these meetings, the General Managers discussed issues, including 1992 performance and accomplishments, 1993 challenges and improvement plans, and weaknesses and strengths of their respective organizations.

The inspector attended selected meetings, reviewed the handouts and discussed these meetings with respective General Managers. The inspector concluded that the licensee demonstrated an effective self assessment capability.

B.

Stations Operations Review Committee (SORC) Meetings During the period, the inspector attended several Salem and Hope Creek SORC meetings.

These included routine weekly and special meetings. The special meetings discussed post trip event reviews and other issues.

The inspector verified that SORC meetings met Technical Specifications and administrative procedure requirements. The inspector concluded that the SORC was effective, and that members displayed a good safety conscious and questioning attitude.

C.

Preparations and Implementation of Adverse Weather Plans

  • On Thursday and Friday March 11 and 12, 1993, Salem and Hope Creek stations prepared for a forecasted severe winter storm. The licensee's preparations included the following:

Reviewed guidance in the related Abnormal Operating Procedures,

Verified availabi}ity of all offsite and onsite power supplies, including the diesel generators with sufficient fuel oil,

Verified operability of all Salem Hope Creek emergency core cooling and containment systems (except Salem Unit 1 No. 14 containment fan coil unit),

Verified operability of all water-tight doors,

Verified manning for site security, checked hardware, prepared for compensatory postings and extra personnel on-call,

Scheduled extra site maintenance personnel for weekend coverage to provide for service water and circulating water intake structure cleaning/inspection,

Maintained periodic contact with the National Weather Service,

Inspected the yard area, including the switchyard, to tie down/remove loose objects and potential missile hazards, and

Reviewed "Acts of Nature" Event Classification Guides.

During the storm, the licensee contacted supplemental personnel to ensure minimum staffing for the operations, security and fire protection organizations. The licensee made provisions for onsite sleeping and food due to the poor site access conditions. All three units maintained full power operation during the weekend storm (March 13 and 14). The Salem units experienced periodic problems with their circulators caused by high winds and tides.

Maintenance and operations personnel performed periodic screen cleanings and shear pin repairs The inspector reviewed the licensee's plans prior to storm arrival and discussed them with plant and corporate management. During the weekend, the inspector contacted by phone each of the control rooms periodically to assess plant status and* storm effects. The inspector concluded that the licensee was proactive and safety conscious in their preparations and implementation of adverse weather plans at both Salem and Hope Creek.

9.

LICENSEE EVENT REPORTS (LER), PERIODIC AND SPECIAL REPORTS, AND OPEN ITEM FOLLOW-UP 9.1 LERs and Reports PSE&G submitted and reviewed for accuracy and evaluation adequacy the following special

. and periodic reports.

  • Salem and Hope Creek Monthly Operating Reports for January and February 1993.*

Salem Unit 2 Special Report 93-1 regarding a planned impairment of a fire barrier penetration seal for greater than seven days.

  • Salem and Hope Creek Semi-Annual Fitness for Duty Performance Data Report for the period ending December 31, 1992.

.

I

  • Salem Semi-Annual Radioactive Effluent Release Report-33.

Hope Creek Semi-Annual Radioactive Effluent Release Report-14 (NLR-N93023).

The inspector concluded that the licensee appropriately issued the above reports.

Salem LERs Unit 1

LER 92-26, Supplement 1 addressed a containment isolation event caused by the lRllA radiation monitor channel on January 25, 1993. The inspectors reviewed this event in NRC Inspection 50-272/93-01, Section 3.2.1.A, and closed the LER.

  • LER 93-01 discussed the inoperability of the analog rod position indication system.
  • The system was intentionally removed from service on two short-duration periods to complete maintenance, requiring entries into Technical Specification 3.0.3. These entries were discussed in NRC Combined Inspection 93-01. Based on the above, the inspector closed this LER.

LER 93-02 discussed a manual reactor trip during a unit shutdown due to a steam dump system malfunction. The inspectors reviewed this event in NRC Inspection 50-272/93-01, and closed the LER

LER 93-03 described the inoperability of the level indication on the No. 11 and 12 boric acid storage tanks on January 13, 1993, and January 27, 1993, respectively.

These events required the licensee to enter Technical Specification 3.0.3 and were documented in NRC Inspection 50-272/91-01. The inspector determined this LER to.

be adequate, will monitor the licensee's corrective actions (See Section 7.1.F of this report), and closed this LER.

Unit 2

LER 92-17 described the unrecognized loss of the overhead annunciator system alarm indication at Salem Unit 2 on December 13, 1992. This event was subsequently inspected by an NRC Augmented Investigation Team (See NRC Inspection 50-272&311/92-81). While open issues exist from the NRC inspection, the inspector determined the LER to be satisfactory and closed this LER.

  • LER 93-01 concerned inoperability of the 2H 4KV group bus underfrequency protection. See Section 4.3.1.A of this report. The inspector closed this LER.
  • LER 93-02 discussed a manual reactor trip from 100 % power upon a loss of both operating steam generator feedwater pumps. The inspectors reviewed this event in NRC Inspection 50-311/92-01. The inspector closed this LER.
  • LER 93-03 described an entry into Technical Specification 3.0.3 on January 31, 1993, due to the inoperability of both boric acid tank level indicators. The inspectors reviewed similar events in NRC Inspection 50-272/93-01 and in Section 7.1.F of this report. The inspector concluded that the licensee's continuing efforts to resolve the level indicator problems are appropriate. The inspector closed this LER.

'

Hope Creek None 9.2 Open Items The inspector reviewed the following previous inspection items during this inspection. These items are tabulated below for cross reference purposes.

Report Section 50-272&311/92-01-01 50-272/93-01-01 Hope Creek 50-354/92-01-02 50-354/92-18-02 50-354/92-04-01 50-354/92-06-02 50-354/92-03-03 5.2.C 7.1.G.

5.2.C 2.2.2.B 4.3.2.A 4.3.2.A 7.2.A Closed Closed Closed Closed Closed Closed Closed

[

10.

EXIT INTERVIEWS/l\\1EETINGS 10.1 Resident Exit Meeting The inspectors met with Mr. V. Polizzi and Mr. R. Hovey and other PSE&G personnel periodically and at the end of the inspection report period to summarize the scope and findings of their inspection activities.

Based on NRC Region I review and discussions with PSE&G, it was determined that this report does not contain information subject to 10 CPR 2 restrictions.

10.2 Specialist Entrance and Exit Meetings Date(s)

3/1-5/93 3/1-5/93'

Subject Salem Outage Preparations Salem Chemistry Inspection Report No.

50-272 and 311/93-06 50-272 and 311/93-07 3/8-12/93 Hope Creek

  • None Commitment Control Program 10.3 Management Meetings A.

Erosion/Corrosion Meeting Reporting Inspector Prell Kattan Leeds On February 11, 1993, PSE&G met with the NRC staff to provide updated information about*

the current Salem/Hope Creek Erosion/Corrosion Program. PSE&G also discussed the status of Salem and Hope Creek licensing actions. * The NRC issued a Meeting Summary under separate correspondence, dated March 3, 1993.

B.

New Jersey Bureau of Nuclear Engineering On March 3, 1993, the NRC resident inspector staff met with inspectors from the New Jersey Department of Environmental Protection and Engineering and the Bureau of Nuclear Engineering. The state representatives were the operations inspectors responsible for the state's oversight of the Salem and Hope Creek power plants. The meeting was conducted in accordance with the Memorandum of Understanding between the NRC and the state of New Jersey.

".

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ATTACHMENT 1 VOLUNTARY ENTRY INTO LCOFORPM NRC/PSE&G MEETING FEBRUARY 25, 1993

PSE&G/NRC MEETING PSE&G PROGRAM

  • NAP 9 * w-oRK CONTROL

-

NET SAFETY GAIN *

-- REDUNDANT EQUIPMENT AVAILABLE AND NO CONCURRENT WORK

_ -

OUT OF SERViCE TIME LIMITED TO 2/3 TECH SPEC r

AOT (> 50% REQUIRES GM APPROVAL)

e NAP 55 * OUTAGE ACTIVITIES

'

'

. e NAP 10 *PM PROGRAM e IMPLEMENTING DOCUMENTS FOR SCHEDULING

1.

.-

PSE&G/NRC MEETING PSE&G PROGRAM e DAILY MANAGEMENT MEETINGS

-

PLANNED OUTAGE SCHEDULE

  • DISCUSS PLANT STATUS EQUIPMENT AVAILABLE PLANNED EVOLUTIONS -
  • COMPARE TO SCHEDULE FOR PROBLEMS
  • ADJUST SCHEDULE/PRIORITIZE WORK e SNSS/NSS

-

FINAL CALL TO-ALLOW SYSTEM TAGOUT BASED ON PLANT CONDITIONS

-

LOGS SYSTEM STATUS AND-POSTS AFFECTED LCO

\\.

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°' I

PSE&G/NRC MEETING SERVICE WATER INTAKE STRUCTURE SILT SURVEY/REMOVAL

  • HISTORY e SILT SURVEYS WERE PERFORMED THROUGHOUT YEAR ~

. REMOVAL DONE AS REQUIRED

  • -

EXPERIENCE INDICATED BUILD-UP OCCURS MORE RAPIDLY DURING SPRING/FALL

-

REMOVAL OF SIGNIFICANT SILT BUILD-UP REQUIRED ANNUALLY.

e ATTEMPTED TO INCORPORATE SILT REMOVAL INTO.

PLANNED SYSTEM OUTAGES

- WORK REQUIRED TO BE DONE IN SERIES RESULTED IN ADDITIVE REAL UNAVAILABILITY

- SIGNIFICANT TIME TO SYSTEM RECOVERY IF NEEDED DUE TO EQUIPMENT DISASS.EMBLY

. PSE&G/NRC MEETING SERVICE WATER INTAKE STRUCTURE SILT SURVEY/REMOVAL e REMOVED SURVEY/REMOVAL FROM SYSTEM OUTAGE SCHEDULE

- WORK DONE ON DAY SHIFT ONLY (NO LONG DAYS)

- NO SHIFT TURN OVER

-

INCREASED PERSONNEL SAFETY (NO NIGHT WORK)

- SYSTEM IS NOT BREACHED/CAN BE RECOVERED IN 15 TO 45.MINUTES (REMOVE DIVER/EQUIPMENT *

CLOSE BREAKER)

...

...

('"

PSE&G/NFIC MEETING *

CONTAINMENT FAN c*ooLER UNIT TESTING e MEETING OUR COMMITMENT TO GL 89*13

-

PHASE I.INSPECT OR TEST

_ PHASE II CONSECUTIVE CYCLES TEST e TEST AT POWER

- TO OBTAIN REALISTIC DATA

-

MAXIMIZE CFCU HEAT LOAD

e SEPARATE LCO ENTRY FOR EACH OF 5 CFCU

-

REDUNDANT TO CONTAINMENT SPRAY e SCHEDULE PRIOR TO OUTAGE

- ALLOW APPROPRIATE SCHEDULING OF CLEANING

.

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