ML20135A946
| ML20135A946 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 03/09/1994 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20135A581 | List: |
| References | |
| FOIA-96-351 EA-94-003, EA-94-3, NUDOCS 9612040103 | |
| Download: ML20135A946 (54) | |
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ENCLOSURE NOTICE OF VIOLATION AND PROPOSED IMPOSITION OF CIVIL PENALTY
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1 Public Service Electric Docket Nos. 50-272; 50-311 and Gas Company License Nos. DPR-70; DPR-75 Salem Nuclear Generating Station EA 94-003 Units 1 & 2 During an NRC inspection conducted from October 17 through November 27,1993, violations of NRC requirements were identified. In accordance with the " General Statement of Policy and Procedure for NRC Enforcement Actions," 10 CFR Part 2, Appendix C, the Nuclear Regulatory Commission proposes to impose a civil penalty pursuant to Section 234 of the Atomic Energy Act of 1954, as amended (Act),42 U.S.C. 2282, and 10 CFR 2.205. The particular violations a6d" associated civil penauy are set forth below:
Salem Technical Specification 6.8.1.a requires that procedures be established, implemented and maintained, covering the activities as described in the applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Appendix A specifies, in part, that procedures be written for equipment control (e.g., locking and tagging), for the control of maintenance, and for the control of i
radioactivity.
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Nuclear Administrative Procedure NC.NA-AP.ZZ-0015(Q), (NAP-15), " Safety Tagging Program," Step 4.1, requires that the job supervisor ensure that equipment has been appropriately tagged and is safe to work on bcrete beginning a work activity, i
Contrary to the above, on October 12, 1993, a contract employee conducted maintenance on a breaker for an elect 2a-hydraulic pump without the job supervisor ensuring equipment was first appropdately tagged out and safe to work on. (01013) 2.
NAP-15, Step 5.4.5.b.6, requires that vents and drains within the tagging boundary be verified in the proper position for equipment operation prior to releasing tags.
9612040103 961120 PDR FOIA O'NEILL96-351 PDR
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Enclosure 2
Contrary to the above, on October 22,1993, an equipment operator removed tags related to maintenance on a bleed steam coil drain tank pump without verification that vents and drains within the tagging boundary were in the proper position for equipment operation prior to releasing the tig. (01023) 3.
NAP-15, Step 5.4.5.c, requires that opentors release tags and reposition mechanical components in accordance with the Tagging Release Worksheet.
Contrary to the above, on October 29,1993, an operator released from a valve a tag not specified on the Tagging Release Worksheet and repositioned the valve while maintenance was in progress on a downstream valve. (01033) 4.
NAP-15, Step 5.1.8, requires job supervisors with personnel working on tagged equipment under their supervision, to tag that equipment in their name or in accordance with a Group Tagging Request.
Contary to the above, on October 31,1993, a job supervisor, wi'h oersonnel working on tagged equipment under his supervision, failed to ensure that a 125 VDC breaker was properly tagged out of service and contiollec in his name or in accordance with a Group Tagging Request to support work on an associated cable, resulting in an electrician cutting into the energized cable. (01043) 5.
Nuclear Administrative Procedure NC.NA-AP.ZZ-0009(Q), (NAP-9), " Work Control Process," Step 2.0, requires that the work control process be applied i
when work is pesformed on Q-rated components, systems and plant structures at the facility.
Contrary to the above, on October 8,1993, licensee personnel performing
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modification work on the auxiliary feedwater system, a Q-rated system, removed spare positioner cams from a system control valve without the work control process being applied, in that a work order was not issued. (01053) 6.
NAP-9, Step 5.7.2, requires that an individual performing work shall perform the work in accordance with the instructions included in the work package.
Contrary to the above, on November 4,1993, Salem maintenance personnel did j
not perform work on a service water inlet isolation valve (No. 23SW58) in accordance with the instructions included in the work package. Specifically, they performed the work in accordance with an unapproved vendor technical manual which had not been included as part of the approved work package. (01063)
a Enclosure 3
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NAP-9, Step 5.1.5.a, requires that any maintenance that can affect the j
performance of Q-rated equipment be performed in accordance with approved 1
written instructions.
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i Contrary to the above, on November 9,1993, during the Unit 1 outage, work was performed on Q-rated equipment without the use of approved ' written instructions. Specifically, contract workers performed wiring changes on a fuel ~
pit heat exchanger motor operated valve without approved written procedures.
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(01073)
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Salem Radiation Protection / Chemistry Procedure SC.RP-TI.ZZ-0209(Q),
" Release OfItems From The Radiologically Controlled Area (RCA)," Step 5.1.3,
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requires that items released from RCA access points be recorded in an active RCA Free Release Log.
Contrary to the above, on November 4,1993, when maintinance personnel removed service water system valve 23SW58, the inlet isolation valve to the No.
23 containment fan coil unit, from the system and subsequently from the RCA access points, the Radiation Protection Department did not document the free release of the valve from the RCA. (01083)
This is a Severity level III problem (Supplement I).
Cumulative Civil Penalty - $50,000 Pursuant to the provisions of _10 CFR 2.201, Public Service Electric and Gas Company (Licensee) is hereby required to submit a written statement or explanation to the Director, Office -
of Enforcement, U.S. Nuclear Regulatory Commission, within 30 days of the date of this Notice j
of Violation'and Proposed Imposition of Civil Penalty (Notice). This reply should be clearly marked as a " Reply to a Notice of Violation" and should include for each alleged violation:
(1) admission or denial of the alleged violation, (2) the reasons for the violation if admitted, and if denied, the reasons why, (3) the corrective steps that have been taken and the results achieved, (4) the corrective steps that will be taken to avoid further violations, and (5) the date when full compliance will be achieved. If an adequate reply is not received within the time specified in i
this Notice, an order or a demand for information may be issued to show cause why the license should not be modified, suspended, or revoked or why such other action as may be proper j
should not be taken. Consideration may be given to extending the response time for good cause
- shown. Under the authority of Section 182 of the Act,42 U.S.C. 2232, this response shall be submitted under oath or affirmation, i
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Enclosure 4
Within the same time as provided for the response required above under 10 CFR 2.201, the Licensee may pay the civil penalty by letter addressed to the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, with a check, draft, money order, or electronic transfer payable to the Treasurer of the United States in the amount of the civil penalty proposed above, or may protest imposition of the civil penalty in whole or in part, by a written answer addressed
.to the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission. Should the Licensee fail to answer within the time specified, an order imposing the civil penalty will be issued. Should the Licensee elect to file an answer in accordance with 10 CFR 2.205 protesting the civil penalty, in whole or in part, such answer should be clearly marked as an " Answer to a Notice of Violation" and may: (1) deny the violations listed in this Notice, in whole or in part, (2) demonstrate extenuating circumstances, (3) show error in this Notice, or (4) show other reasons why the penalty should not be imposed. In addition to protesting the civil penalty in whole or in part, such answer may request remission or mitigation of the penalty.
In requesting mitigation of the proposed penalty, the factors addressed in Section V.B of 10 CFR Part 2, Appendix C (1992), should be addressed. Any Mitten answer in acconuance with 10 CFR 2.205 should be set forth separately from the statement or explanation in reply pursuant to 10 CFR 2.201, but may incorporate parts of the 10 CFR 2.201 reply by specific reference (e.g., citing page and paragraph numbers)'to avoid repetition. The attention of the Licensee is directed to the other provisions of 10 CFR 2.205, regarding the procedure for imposing a civil penalty.
Upon failure to pay any civil penalty due which subsequently has been determined in accordance with the applicable provisions of 10 CFR 2.205, this matter may be referred to the Attorney General, and the penalty, unless compromised, remitted, or mitigated, may be collected by civil action pursuant to Section 234c of the Act,42 U.S.C. 2282(c).
The response noted above (Reply to Notice of Violation, letter with payment of civil penalty, and Answer to a Notice of Violation) should be addressed to: James Lieberman, Director, Office of Sforcement, U.S. Nuclear Regulatory Commission, ATrN: Document Control Desk, Washington, D.C. 20555 with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission, Region I,475 Allendale Road, King of Prussia, Pennsylvania 19406 and a copy to the Senior Resident Inspector, Salem Generating Station.
j Dated at King of Prussia, Pennsylvania this M day of March 1994
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SALEM UNIT 1 REACTOR TRIP WITH MULTIPLE l
SAFETY INJECTIONS r
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APRIL 7,1994 l
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SEQUENCE OF EVENTS l
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INITIAL CONDITIONS ON APRIL 7,1994:
l REACTOR POWER AT 75%
CONTROL RODS IN MANUAL 1
OF 6
CIRCULATING WATER PUMPS O UT-O F-l SERVICE j
10:16 to 10:43 a.m.
POWER REDUCTION DUE TO CLOGGING OF CIRCULATING WATER SCREENS BY RIVER GRASS. 5 OF 6 CIRCULATING i
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SEQUENCE OF EVENTS (cont.?
I WATER PUMPS TRIP OUT OF SERVICE.
UP TO 6 OF 6 CIRCULATING WATER SCREENS WERE OUT-OF-SERVICE (BROKEN SHEAR PINS OR SCREEN CLEANING?
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i 10:44 to 10:47 RCS TEMPERATURE DECREASES BELOW LOW-LOW l
- SETPOINT, PLANT POWER AT 80 MWE.
OPERATOR PULLS RODS TO RESTORE RCS TEMPERATURE.
a REACTOR POWER INCREASES FROM 7% TO 25%
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SEQUENCE OF EVENTS (cont.?
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_10:47 REACTOR TRIPS AT 25% POWER RANGE LOW SETPOINT.
AUTOMATIC SAFETY INJECTION OCCURS ON HIGH STEAM FLOW WITH LOW-LOW Tave ("A" PROTECTION TRAIN LOGIC ONLY)
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10:49 to 11:05 OPERATORS ENTER EMERGENCY OPERATING PROCEDURES.
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SEQUENCE OF EVENTS fcont.?
11:05 to 11:26 PRESSURIZER PORVs AUTO OPEN ON HIGH PRESSURE THE PRESSURIZER FILLS TO THE SOLID CONDITION OPERATORS IDENTIFY THAT THE SAFETY INJECTION l
WAS NOT NECESSARY, TERMINATE THE ECCS INJECTION, AND COMMENCE RECOVERY ACTIONS TO RESTORE THE PLANT TO NORMAL CONTROL.
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.T SEQUENCE OF EVENTS Leont.)
A STEAM GENERATOR SAFETY VALVE OPENS CAUSING i
THE RCS TO COOLDOWN AND DEPRESSURIZE 11:26 D
OPERATORS DECIDE TO MANUALLY RE-INITIATE ECCS DUE TO RAPID RCS PRESSURE DECREASE.
t PRIOR TO THE OPERATOR ACTION, A SECOND ACTUAL AUTOMATIC SI OCCURS DUE TO LOW PRESSURIZER PRESSURE ("B" PROTECTION TRAIN OF LOGIC?.
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SEQUENCE OF EVENTS (cont.511:41 OPERATORS RESET THE SECOND SI.
OPERATORS USE SOLID PLANT PRESSURE CONTROL (CHARGING AND LETDOWN).
11:49 PRESSURIZER POWER OPERATED RELIEF VALVES CONTINUE TO ACTUATE.
PRESSURIZER PORVs HAD ALREADY ACTUATED >300 TIMES TO MAINTAIN RCS l
PRESSURE WITHIN ACCEPTABLE PRESSURE RANGE.
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SEQUENCE OF EVENTS (cont.)
PRESSURIZER RELIEF TANK RUPTURE DISK RUPTURES DUE TO THE AMOUNT OF REACTOR COOLANT RELEASED BY THE PRESSURIZER PORVs.
1:16 ALERT DECLARATION TO ENSURE PROPER TECHNICAL STAFF AVAILABLE TO ASSIST PLANT OPERATORS IN RECOVERY TO NORMAL CONDITIONS FROM THE SOLID PLANT.
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t SEQUENCE OF EVENTS (cont.)
4:30 i
THE OPERATORS ESTABLISH A STEAM SPACE IN THE PRESSURIZER (NO LONGER SOLID).
THIS ALLOWS THE OPERATORS TO MAINTAIN RCS PRESSURE AND LEVEL i
WITH NORMAL CONTROLS.
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5:15-i OPERATORS EXIT EMERGENCY OPERATING PROCEDURES l
AND COMMENCE A NORMAL PLANT COOLDOWN USING THE NORMAL SHUTDOWN PROCEDURE.
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CAUSAL FACTOR ANALYSIS FOR KEY EVENTS m
THE REACTOR TRIP WAS A RESULT OF HUMAN ERROR a
THE INITIAL " SAFETY INJECTION" WAS A RESULT OF:
l A DESIGN DEFICIENCY: THE HIGH STEAM FLOW INSTRUMENTS ERRONEOUSLY IDENTIFIED A
PRESSURE PULSE AS AN ACTUAL HIGH STEAM i
FLOW CONDITION; AND i
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i CAUSAL FACTOR ANALYSIS FOR KEY EVENTS (cont.)
i HUMAN ERROR:
OPERATORS ALLOWED THE REACTOR COOLANT SYSTEM TEMPERATURE TO GO LOW.
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a THE " UNEXPECTED" EQUIPMENT RESPONSE TO THE INITIAL SI WAS DUE TO THE DESIGN OF THE j
PROTECTION LOGIC AND THE TIME IT TAKES FOR j
RELAYS TO ACTUATE.
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" SAFETY INJECTION" WAS DUE TO HUMAN ERROR IN MAINTAINING TEMPERATURE AND j
PRESSURE WITHIN NORMAL, NO-LOAD CONDITIONS.
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CAUSAL FACTOR ANALYSIS FOR KEY EVENTS (cont.?
a THE HUMAN ERRORS THAT OCCURRED WERE ALL COMPLICATED BY PRE-EXISTING EQUIPMENT PROBLEMS THAT RESULTED IN THE OPERATORS HAVING TO RELY ON
" MANUAL" OPERATIONS INSTEAD OF NORMAL, " AUTOMATIC" CONTROLS.
m THESE PRE-EXISTING CONDITIONS WERE ACCEPTED BY MANAGEMENT AND INDICATE A MANAGEMENT WEAKNESS IN MAINTAINING EQUIPMENT IN LESS j
THAN OPTIMAL CONDITION.
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SAFETY SIGNIFICANCE L
m EVENTS-OF 4/7/94 DEPICTED AN UNUSUAL i
TRANSIENT IN WHICH PLANT CONDITIONS i
CHALLENGED BOTH THE ' AUTOMATIC PROTECTIVE FEATURES AND THE OPERATORS WHO CONTROLTHE-PLANT.
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SOME EQUIPMENT PERFORMANCE WAS NOT AS 4
EXPECTED AND OPERATOR PERFORMANCE i
EXHIBITED SOME WEAKNESS.
a HOWEVER, ALL THREE PHYSICAL BARRIERS (FUEL
- CLADDING, RCS PRESSURE
- BOUNDARY, CONTAINMENT? PERFORMED ACCEPTABLY.
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SAFETY SIGNIFICANCE (cont;l m
THERE WAS NO EVIDENCE OF DAMAGE TO EITHER THE FUEL OR ITS CLAD OR TO THE CONTAINMENT.
THERE WAS MINOR, BUT IMPORTANT, DEGRADATION OF THE PRESSURIZER PORVs (IN 94-55;i AND THE PRT l
RUPTURE DISK BLEW.
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A SIGNIFICANT CONCERN IDENTIFIED WAS THAT THE AUTOMATIC SAFETY INJECTION SYSTEM OPERATED IN A WAY THAT REQUIRED EXTENSIVE OPERATOR i
ACTION:
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SAFETY SIGNIFICANCE (cont.)
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i OPERATOR ACTION EXTENDED THE TIME TO MEET i
THE EMERGENCY CORE COOLING INJECTION TERMINATION CRITERIA IN THE EMERGENCY OPERATING P'ROCEDURES.
THIS RESULTED IN THE ECCS INJECTION l
PRODUCING A " SOLID" RCS.
THE SOLID RCS LED TO RELIANCE ON PRESSURIZER PORVs TO CONTROL RCS PRESSURE RESULTING IN MULTIPLE OPENING OF THE TWO VALVES I
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SAFETY SIGNIFICANCE (conth OPERATION OF THE PORVs FROM THE WATER SOLID CONDITION COULD HAVE CHALLENGED THE RCS PRESSURE BOUNDARY.
THE DEGRADATION OF THE PORVs REQUIRED REPAIRS TO THE INTERNAL COMPONENTS OF THE VALVES.
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q SALEM AIT ANALYSIS 50-272/94-80 APRIL 8,1994 REVIEW OF THE CIRCUMSTANCES SURROUNDING THE SALEM UNIT 1 TRIP ON APRIL 7,1994, AND THE UNEXPECTED RESPONSE OF PLANT SYSTEMS l
BACKGROUND:
Salem Unit I tripped on April 7,1994 as a result of grass intrusion affecting the operation of circulating water (CW) pumps at the intake structure. Plant power was maneuvered in response to increasing condenser backpressure and rapid changes in RCS temperature to resolved power mismatch conditions. The plant tripped at 25% power. Subsequently, there was unexpected response of the Safety Injection System due.to SSPS logic which caused the plant to go solid.
Compounding conditions included problems with the Atmospheric Steam Dumps valves, and rapid and frequent cycling of the PORV valves resulting in PRT mpture disk blowout.
Additionally, nitrogen gas subsequently collected in the vessel head.
ROOT CAUSE:
l Poor operator performance, performance errors and weak communications during power l
maneuvers to maintain plant operations while circulating water was being affected by grass intrusion.
Extensive grass intmsion which exceeded the ability of the existing circulating water intake structure traveling screens.
l Pre-existing equipment abnormalities involving the automatic control rod system, false high j
steam flow signals as a result of plant trip action 3, and MS-10 atmospheric relkt valve reset l
wind-up problems were allowed to continue as work-around conditions. (Operator failure to follow training instructions and poor communications contributed to problems associated with i
manual MS-10 response and operation.)
l CORRECTIVE ACTIONS (generally applicable to both Salem units):
Operator training was enhanced to address performance weaknesses; subsequently, operator l
performance was validated; Procedures were revised to provide better and more conservative guidance to operators in an i
effort to avoid conditions or plant maneuvers that have the potential to result in challenges to I
safety systems; Long-term plans established to improve circulating water intake stmeture traveling screen performance relative to debris and grass handling;
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All pre-existing work-around conditions were resolved by re; air or design change to support plant Unit-1 restart; similar repair and design changes are planned for Unit-2 next outage; compensatory measures such as procedure revisions and operator refresher have been completed for Unit-2 for the interim period; other existing conditions are being evaluated for potential effect on plant response.
CORRECTIVE ACTION EFFECTIVENESS:
To soon to tell.
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50-311/93-81 i
JUNE 5,1993 REVIEW OF CIRCUMSTANCES SURROUNDING SEVERAL ROD CONTROL SYSTEM FAILURES AT SALEM UNIT 2 DURING START UP ACTIVITIES FROM MAY 25 THROUGH JUNE 3,1993 BACKGROUND:
During startup, Salem Unit 2 experienced multiple failures of the control rod control system (CRCS). Five plant startup attempts were made from May 25 to June 3,1993. The failures involved failure CRCS to move the rods correctly and maintain them in the proper position. The most serious event involved erroneous indications on rod position indicators as compared to step counters, and withdrawal of a rod from the core without a demand signal and without response to operator actions to control the movement until power was removed form the rod. Due to the numerous abnorm 11 occurrences in such a short time, NRC was concerned about the approach the licensee was using to determine cause and establish effective corrective actions.
ROOT CAUSE:
i Process causes:
1 Restart process (station policy and procedures) did not provide for programmatic determmation of root cause of system failure, i.e., there was no clear policy on when, how, and to what extent, to perform root cause analysis for component failures.
Ilardware causes:
Multiple integrated circuit and output transistor failures due to unsuppressed voltage spikes.
Regulation board short circuits created during manufacturing or maintenance activities.
Slave cycler logic card failures due to power supply short circuit or unsuppressed voltage spikes.
Q9 transistor failures due to jumpering activities performed for troubleshooting.
Wrong resistor installed on failure detector card due to manufacturing error.
CORRECTIVE ACTIONS:
(Applies to all Salem units)
CPAT effort is expected to address the lack on organized approach to root cause analysis and troubleshooting activities.
Standing Orders have been developed to provide additional guidance to operators relative to operability determinations (CPAT actions are also expected to enhance operability guidance).
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Troubleshooting procedure has been significantly revised to provide more comprehensive guidance relative to root cause and troubleshooting processes.
Vendor supplied materials are required to go through Procurement and Material Control inspection prior to use in the plant.
Component and circuitry modifications and repairs completed and tested satisfactorily; design changes instituted for digital demand step counters.
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CORRECTIVE ACTION EFFECTIVENESS:
Recurrence of problems of this type have not been observed since this event.
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50-311/92-81 DECEMBER 14, 1992 REVIEW OF CIRCUMSTANCES SURROUNDING LOSS OF THE OVERHEAD ANNUNCIATOR SYSTEM AT SALEM UNIT 2 ON DECEMBER 13, 1992 BACKGROUND:
On December 13,1992, a Salem Unit 2 operator discovered that the overhead annunciators had not been updating alarms for about 90 minutes. The operator reset and restored the system within two minutes. Subsequent investigation revealed that a member of the operating crew had been using the Remote Configuration Workstation (RCW) computer and had inadvertently entered a keystroke combination that, when input through the wrong system port, prevented the proper operation of the overhead annunciator system.
ROOT CAUSE:
An operator failed to follow procedures relative to the operation of the Remote Configuration 4
Workstation (RCW) which affects the function of the Sequence of Events Recorder and its
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interface with the overhead annunciator.
No alarms or warning were available to alert the operator of mis-positioned switen at the RCW, therefore operators were not aware of OHA status.
Design specifications for OHA were LTA relative to alarm / warning features Other items:
No loss of annunciator procedure.
Operators were not trained on routine verification of proper system operation.
LTA software review.
Operators knowledge of need to declare Alert on system failure.
General communications with NRC CORRECTIVE ACTIONS:
Design change to incorporate alarm / warning feature to warn of OHA system malfunctioning.
New procedure for loss of OHA 6
New security features added to RCW to prevent inadvertent or non-authorized manipulation of system diagnostic computer.
Operator training lesson plans developed and incorporated in training program; OHA malfunction added to simulator training program.
Personnel disciplinary action taken.
NRC reporting and ECG criteria clarified relative to loss of OHA New procedures developed and issued relative to specifications for software and software verification and validation processes; revision of vendor technical manual by vendor; lesson plans developed for system training.
PSE&G and vendor developing less complicated system testing process.
Software vims checks performed.
Managements expectations relative to communicating concerns with faulty syst..n operation conveyed in series of roll-down meetings.
CORRECTIVE ACTION EFFECTIVESTSS:
No similar problems have been noted since this event.
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50-311/91-81 NOVEMBER 10, 1991 REVIEW OF CIRCUMSTANCES INVOLVING THE CATASTROPHIC FAILURE (DESTRUCTION AND FIRE) OF THE SALEM UNIT 2 TURBINE-GENERATOR ON NOVEMBER 9,1991 i
BACKGROUND:
The Salem Unit 2 Turbine-Generator was severely damaged, while at 100% power, on November 9,1991, during performance of Front Standard testing of automatic mechanical turbine trip features. During the test, normal turbine trip functions are isolated and reliance is placed on the ET-20 emergency trip solenoid and two overspeed protection solenoids to function.
While testing, a momentary AST oil pressure perturbation resulted in momentary closure of turbine steam admission valves, reactor trip, and subsequent load drop from the generator.
However, the ET-20 and the overspeed protection solenoids failed to function due to mechanical binding. Consequently, once AST oil pressure returned to normal, hydraulic fluid which normally would have been drained by the functioning of the turbine control solenoid valves, was pressurized to reopen the steam admission valve to the tusoine. Subsequently tne turbine experienced severe overspeed without any abatement until the operators restored the Front Standard test controls to the normal position, at which time AST-20 functioned to close the j
turbine steam admission valves. The turbine generator was subject to severe damage and fire.
ROOT CAUSE:
Three separate solenoid valves failed to function as designed to control turbine overspeed and effect turbine trip.
Insufficient preventive maintenance afforded to the turbine overspeed protection system.
Inadequate surveillance testing of solenoid valve-actuated turbine control systems.
Delayed replacement of Unit 2 solenoid valves after previous component failures were identified at Unit 1.
Failure of management and operating personnel to follow procedures and effectively resolve a failed test result involving the turbine overspeed protection system during a previous turbine startup procedure on October 21,1991.
CORRECTIVE ACTIONS (applies to both Units,):
Disciplinary action taken against individuals who failed to follow the requirements of the turbine stanup procedure on October 21,1991.
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i Management expectations communicated to staff relative to the importance of procedure adherence.
1 Operator training revised to include simulator and classroom instruction relative to turbine control system functioning and testing; all operators trained; operator effectiveness evaluated.
j Turbine startup procedures revised and upgraded.
" Conduct of Operations" training, relative to procedural adherence, provided to station staff.
Human performance analysis initiated with lessons-learned to be incorporated.
Commitment Management procedure developed and issued to assure that all commitments and previous LERs are tracked and completed in a timely manner; several other planning and scheduling procedures were revised to assure the proper assignment of priority to items that require action.
Preventive maintenance program established for oritices in the AST system.
Design change for filter installation on AST orifices completed.
Front standard test procedure upgraded and revised.
INPO Awareness Training conducted, Resource Management, and Supervisory and Management Effectiveness i
Solenoid valves replaced; turbine EHC systems and components have been incorporated in Reliability Centered Maintenance program to assure PM performance; vendor identified PM specifications.
Surveillance program for solenoids revised to independently test each unit and verify function.
Tachometer and recorders reconnected.
Design change completed to provide backup to AST-20 so that it would not be isolated during Front standard testing procedures; electrical overspeed channel was added by design change.
Tech Spec have been amended to clarify operability determinations relative to turbine system surveillance requirements.
CORRECTIVE ACTION EFFECTIVENESS:
No recurrence of similar problems noted.
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i OVERALL CORRECTIVE ACTION EFFECTIVENESS:
Recurrent instances of failure to follow procedures despite numerous efforts by management to l
ameliorate this common problem.
Management effectiveness is questionable and a contributor in each occurrence.
Operator training is usually an identified item that requires remedial action.
Communication effectiveness is a common feature in these events.
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7 SALEM AIT ANALYSIS 4
h 50-272/94-80 l
APRIL 8, 1994 REVIEW OF THE CIRCUMSTANCES SURROUNDING THE SALEM UNIT 1 TRIP ON APRIL 7, 1994, AND THE UNEXPECTED RESPONSE OF PLANT SYSTEMS
-BACKGROUND:
4 Salem Unit 1 tripped on April 7, 1994 as a result'of grass intrus
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circulating water (CW) pumps at the intake structure.
Plant powe to increasing condenser backpressure and rapid changes;in RCS tem mismatch conditions.
The plant tripped at 25% power.
Subsequent i
response of the safety Injection System due to SSPS logic which c Compounding conditions included problems with the Atmospheric Ste rapid'and frequent cycling of the PORV valves resulting in PRT ru Additionally, nitrogen gas subsequently collected in the vessel h l
ROOT CAUSE:
- Poor operator performance, performance errors and weak communicat maneuvers to maintain plant operations while circulating water wa intrusion.
. Extensive grass intrusion which exceeded the ability of the exist structure traveling screens.
Pre-existing equipment abnormalities involving the automatic cont steam flow signals as a result of plant trip actions, and MS-10 a wind-up problems were allowed to continue as work-around conditio follow training' instructions and poor communications contributed manual MS-10 response and operation.)
CORRECTIVE ACTIONS (generally applicable to both Salem units) :
Operator training was enhanced to address performance weaknesses; performance was validated; Procedures were revised to provide better and more conservative g-effort to avoid conditions or plant maneuvers that have the poten safety systems; Long-term plans established to improve circulating water intake s 4
performance relative to debris and grass handling; All pre-existing work-around conditions were resolved by repair o plant Unit-1 restart; similar repair and design changes are plann compensatory measures such as procedure revisions and operator re for Unit-2 for the interim period; other existing conditions are p
effect on plant response.
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CORRECTIVE ACTION EFFECTIVENESS:
n To soon to tell.
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50-311/93-81 JUNE 5, 1993 REVIEW OF CIRCUMSTANCES SURROUNDING SEVERAL ROD CONTROL SYSTEM i
FAILURES AT SALEM UNIT 2 DURING START UP ACTIVITIES FROM MAY 25 j
THROUGH JUNE 3, 1993 BACKGROUND:
4 During.startup, Salem Unit 2 experienced multiple failures of the (CRCS).
Five plant startup attempts were made from May 25 to Jun
)4 involved failure CRCS to move the rods correctly and maintain the most serious event involved erroneous indications on rod position i
counters, and withdrawal of a rod from the core without a demand to operator actions to control the movement until power was remov j
numerous abnormal occurrences in such a short time, NRC was conce the licensee was using to determine cause and establish effective s
ROOT CAUSE:
4 Process causes:
Restart process (station policy and procedures) did not provide f of root cause of system failure, i.e.,
there was no clear policy 4
i extent, to perform root cause analysis for component failures.
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Hardware causes:
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Multiple integrated circuit and output transistor failures due to Regulation board short circuits created during manufacturing or m Slave cycler logic card failures due to power supply short circui 09 transistor failures due to jumpering activities performed for Wrong resistor installed on failure detector card due to manufact CORRECTIVE ACTIONS:
(Applies to all Salem units)
CPAT effort is expected to address the lack on organized approach troubleshooting activities.
Standing orders have been developed to provide additional guidanc operability determinations (CPAT actions are also expected to en Troubleshooting procedure has been significantly revised to provi guidance relative to root cause and troubleshooting processes.
Vendor supplied materials are required to go through Procurement inspection prior to use in the plant.
Component and circuitry modifications and repairs completed and t changes instituted for digital demand step counters.
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CORRECTIVE ACTION EFFECTIVENESS:
Recurrence of problems of this type have not been observed since 1
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l 50-311/92-81 l
DECEMBER 14, 1992 REVIEW OF CIRCUMSTANCES SURROUNDING LOSS OF THE OVERHEAD I
ANNUNCIATOR SYSTEM AT SALEM UNIT 2 ON DECEMBER 13, 1992 i
j BACKGROUND:
On December 13, 1992, a Salem Unit 2 operator discovered that the l
not been updating alarms for about 90 minutes.
The operator rese within two minutes. Subsequent investigation revealed that a memb been using the Remote Configuration Workstation (JRCW) computer an entered a keystroke combination that, when input through the wron l
l proper operation of the overhead annunciator system.
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ROOT CAUSE:
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An operator failed to follow procedures relative to the operation l
Workstation (RCW) which affects the function of the Sequence of E interface with the overhead annunciator.
i No alarms or warning were available to alert the operator of mis-l therefore operators were not aware of OHA status.
Design specifications for OHA were LTA relative to alarm / warning j
l Other items:
l No loss of annunciator procedure.
i operators were not trained on routine verification of proper syst i
LTA software review.
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Operators knowledge of need to declare Alert on system failure.
General communications with NRC CORRECTIVE ACTIONS:
Design change to incorporate alarm / warning feature to warn of OHA New procedure for loss of OHA New security features added to RCW to prevent inadvertent or non-system diagnostic computer.
Operator training lesson plans developed and incorporated in trai malfunction added to simulator training program.
Personnel disciplinary action taken.
NRC reporting and ECG criteria clarified relative to loss of OHA New procedures developed and issued relative to specifications fo verification and validation processes; revision of vendor technic l
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plans developed for system training.
j PSE&G and vendor developing less complicated system testing proce Software virus checks performed.
Managements expectations relative to communicating concerns with conveyed in series of roll-down meetings.
CORRECTIVE ACTION EFFECTIVENESS:
No similar problems have been noted since this event.
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W 50-311/91-81 NOVEMBER 10, 1991 REVIEW OF CIRCUMSTANCES INVOLVING THE CATASTROPHIC FAILURE (DESTRUCTION AND FIRE) OF THE SALEM UNIT 2 TURBINE-GENERATOR ON NOVEMBER 9, 1991 BACKGROUND:
The Salem Unit 2 Turbine-Generator was severely damaged, while at November 9, 1991, during performance of Front Standard testing of turbine trip features.
During the test, normal turbine trip func placed on the ET-20 emergency trip solenoid and two overspeed pro While testing, a momentary AST oil pressure perturbation resulted turbine steam admission valves, reactor trip, and subsequent load However, the ET-20 and the overspeed protection solenoids failed binding.
Consequently, once AST oil pressure returned to normal, normally would have been drained by the functioning of the turbin pressurized to reopen the steam admission valve to the turbine.
anperienced severe overspeed without any abatement until the oper Standard test controls to the normal position, at which time AST-turbine steam admission valves.
The turbine generator was subjec ROOT CAUSE:
Three separate solenoid valves failed to function as designed to effect turbine trip.
Insufficient preventive maintenance afforded to the tu_bine overs Inadequate surveillance testing of solenoid valve-actuated turbin Delayed replacement of Unit 2 solenoid valves after presious comp at Unit 1.
Failure of management and operating personnel to follow procedure failed test result involving the turbine overspeed protection sys startup procedure on October 21, 1991.
CORRECTIVE ACTIONS (applies to both Units,):
Disciplinary action taken against individuals who failed to follo startup procedure on October 21, 1991.
Management expectations communicated to staff relative to the imp adherence.
Operator training revised to include simulator and classroom inst control system functioning and testing; all operators trained; op Turbine startup procedures revised and upgraded.
" Conduct of Operations" training, relative to procedural adherenc Human performance analysis initiated with lessons-learned to be i
.r Commitment Management procedure develooed and issued to assure th previous LERs are tracked and completed in a timely manner; sever-scheduling procedures were revised to assure the proper assignmen require action.
Preventive maintenance program established for orifices in the AS Design change for filter installation on AST orifices completed.
Front standard test procedure upgraded and revised.
INPO Awareness Training conducted, Resource Management, and Super Effectiveness Solenoid valves replaced; turbine.EHC systems and components have Reliability Centered Maintenance program to assure PM performance specifications.
Surveillance program for solenoids revised to independently test Tachometer and recorders reconnected.
Design change completed to provide backup to AST-20 so that'it wo Front standard testing procedures; electrical overspeed channel w Tech Spec have been amended to clarify operability determinations surveillance requirements.
CORRECTIVE ACTION EFFECTIVENESS:
No recurrence of similar problems noted.
e OVERALL CORRECTIVE ACTION EFFECTIVENESS:
Recurrent instances of failure to follow procedures despite numer ameliorate this common problem.
Management effectiveness is questionable and a contributor in eac Operator training is usually an identified item that requires rem Communication effectiveness is a common feature in these events.
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27053 l
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11:31[ET]lg l FACILITY:
lNOTIFICATIONDATE: 04/07/94 SALEM REGION:
1 UNIT:
[1] [ ] [ ]
STATE: NJ NOTIFICATION TIME:
g g
EVENT DATE:
04/07/94 RX TYPE: [1] W-4-LP,[2] W-4-LP i
10:47[EDT)g i
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l lNRCNOTIFIEDBY HEDMON lLAST UPDATE DATE:
04/08/94 e
i Q OPS OFFICER: CHAUNCEY GOULD
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NOTIFICATIONS l
EMERGENCY CLASS: ALERT
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l 10 CFR SECTION:
lWALTERPASCIAK RDO gAAEC 50.72(a)(1)(i)
EMERGENCY DECLARED GRIMES EO y
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l SIMMERS FEMA l
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y
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l UNIT l SCRAM CODE lRX CRIT lINIT PWRl INIT RX MODE lCURR PWRl CURR RX MODE l
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A/R Y
75 POWER OPERATION l 1
0 HOT STANDBY l
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EVENT TEXT
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1 lTHEPLANTHADAREACTORTRIPFROM25%POWERONPOWERLOWRANGE/HIGHFLUX l
SIGNAL AND A SAFETY INJECTION INITIATION ON LOW-LOW TAVG COINCIDENT WITH l
l l HIGH STEAM FLOW.
l THE LICENSEE WAS LOWERING REACTOR POWER BECAUSE OF THE LOSS OF SOME CIRCULATING WATER PUMPS AT THE TIME OF THE TRIP.
POWER WAS LOWERED TO LESS THAN 10%, THUS AUTOMATICALLY INSTATING THE LOW POWER TRIP SET POINT OF 25%.
THE LICENSEE HAS SPECULATED THAT OPERATORS BEGAN WITHDRAWING CONTROL RODS TO RESTORE A LOWER THAN NORMAL TAVG.
POWER INCREASED TO 25%, AND A REACTOR l
g g TRIP WAS RECEIVED, ALL RODS FULLY INSERTED.
g A SAFETY INJECTION SIGNAL WAS RECEIVED BECAUSE OF A LOW LOW TAVG IN CONJUNCTION WITH HICH STEAM FLOW SIGNAL. AT LEAST TWO MAIN STEAM I!DLATION g
g VALVES AND TWO FEED WATER ISOLATION VALVES FAILED TO CLOSE AS REQUIRED, IN l
g g ADDITION, THE MAIN FEED PUMPS FAILED TO TRIP.
THE SUBSEQUENT COOLDOWN OF l
l THE REACTOR COOLANT SYSTEM CAUSED PRESSURIZER PRESSURE AND LEVEL TO DROP. A l
g SECOND SAFETY INJECTION SIGNAL WAS RECEIVED ON LOW PRESSURIZER PRESSURE.
g THE PLANT WAS TAKEN SOLID BY THE HIGH HEAD SAFETY INJECTION PUMPS. THE POWER OPERATED RELIEF VALVES (PORVs) ON THE PRESSURIZER OPENED AND RELIEVED l
g g TO THE PRESSURIZER RELIEF TANK (PRT).
THE BLOW OUT DISC ON THE PRT BLEW g
OUT TO PREVENT OVER PRESSURIZATION OF THE TANK.
THE PRT RELIEVES TO THE g
g CONTAINMENT.
g g
- UPDATE AT 11:55 4/7/94 FROM HEDMON TO GOULD*** AT 11:26 THE "11" STEAM g GENERATOR SAFETY VALVE LIFTED AND FULLY RESEATED. THE COOLDOWN RESULTED IN g
A DECREASE IN RCS PRESSURE. THIS WORKED IN CONJUNCTION WITH THE OVER g
g FEEDING TO CAUSE THE SECOND SI SIGNAL.
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- UPDATE O 13:53 4/7/94 FROM HEDMON TO MCGINTY * **
l LICENSEE DECLARED A PRECAUTIONARY ALERT AT 13:16 4/7/94 TO HELP STAFF THE g
TSC IN RESPONSE TO THE ABOVE EVENf.
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- UPDATE AT 1602 EDT BY KARSCH * *
- COMMISSIONER'S ASSISTANTS BRIEFING g (RIEFER B
(WENSINGER) RGN 1, ATTENDEES AEOD (JORDAN & HOLAHAN), IRB gg
{
i BROCKMAN), PA (BEECHER), SP (LOHAUS), EDO (TATUM), NRR EO (DENNIG), SECY
\\y
^ \\l 4
1 e
a (BATES), CA (MADDEN), ROGERS' (SORENSEN), SELIN'S (BAKER), REMICK'S (GOODMAN), DePLANQUE'S (RULAND), OTHERS NRR (DENBECK), NRR/RSB (COLLINS).
' THE LICENSEE HAS DRAWN A BUBBLE IN THE PRESSURIZER AND INTENDS TO LOWER PRESSURIZER LEVEL TO 50% AND BEGIN A NORMAL COOLDOWN TO COLD SHUTDOWN.
g THE FOLLOWING AGENCIES WERE NOTIFIED OF THE ALERT AND ITS TERMINATION:
1
- 1. DOE (VISNOSKY)
- 2. USDA(COOPER / GRAHAM)
- 3. HHS(BURGER)
- 4. FEMA (SIMMERS /CARR)
- 5. EPA (LYMON/CONKLIN)
UPDATE DATE/ TIME 4/8/94 0 0410 BY:McGINTY ***
AS OF 0410 EST ON 4/8/94, THE PLANT IS IN MODE 4 AT 370 psig AND 350F.
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PREPARATIONS ARE BEING MADE TO PLACE RHR ON SERVICE. THE LICENSEE ANTICIPATES REACHING COLD SHUTDOWN AT ABOUT NOON, TODAY.
THE LICENSEE HAD NO NEW INFORMATION TO REPORT REGARDING THE EVENT.
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O April 8,1994 Docket No. 50 272 License No. DPR-70 CAL No.1-94-005 Mr. Steven E. Miltenberger Vice President and Chief Nuclear Officer Public Service Electric and Gas Company P.O. Box 236 Hancock's Bridge, New Jersey 08038
Dear Mr. Miltenberger:
SUBJECT:
CONFIRMATORY ACTION LETTER 1-94-005 On April 7 and 8,1994, in telephone discussions, William Kane, Deputy Regional Administrator, informed Mr. Joseph Hagan, Acting General Manager, Salem Nuclear Generating Station, of our decision to dispatch an Augmented inspection Team (AIT) to review and evaluate the circumstances and safety significance of the Unit I reactor trip and safety injection that occurred on April 7,1994. The event was complex and may have involved personnel error, equipment failure, or a combination of both. The AIT was initiated because of the complexity of the event, the uncertainty of the root causes of some of the conditions and equipment problems encountered during the event, concerns relative to the proper functioning of engineered safety features, and possible generic implications. The AIT, led by Mr. Robert Summers of our office, is expected to commence their activities at the Salem Nuclear Generating Station on April 8, 1994.
In response to our request, Mr. Hagan agreed to place Salem Unit 1 in a cold shutdown condition and maintain that condition until the AIT acquired all the information needed for their i
assessment and was satisfied that any necessary corrective measures have or would be taken; and
)
that your staff would take actions to:
i 1.
Assure that the AIT I.cader is cognizant of, and agrees to, any resumption of activities that involve the operation, testing, maintenance, repair, and surveillance of any equipment, including protection logic or associated components, which failed to properly actuate in response to the reactor trip and safety injection (s) of April 7,1994.
2.
Assemble or otherwise make available for review by the AIT, all documentation (including analyses, assessments, reports, procedures, drawings, personnel training and qualification records, and correspondence) that have pertinence to the equipment problems leading up to the reactor trip and safety injection (s), and subsequent operator response and recovery actions.
3
(- kj f r W S S gp
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3.
Assemble or otherwise make available for review by the AIT, all equipment, assemblies, and components that were associated with the problems encountered during the events 3
leading up to, and subsequent to the reactor trip and safety injection (s).
]
4.
Make available for interview by the AIT, all personnel that were associated with, or have information or knowledge that pertains to tne problems encountered during the events i
i leading up to, and subsequent to the reactor trip and safety injection (s).
'5.
Gain my agreement prior to commencing any plant startup.
Pursuant to Section 182 of the Atomic Energy Act,42 U.S.C. 2232, and 10 CFR 2.204, you j
are hereby required to:
I 1.
Notify me immediately if your understanding differs from that set forth above.
4 2.
Notify me, if for any reason, you require modification of any of these agreements.
5 l-Issuance of this Confirmatory Action Letter does not preclude issuance of an Order formalizing the above commitments or requiring other actions on the part of the licensee, nor does it preclude the NRC from taking enforcement action if violations of NRC regulatory requirements are identified through the actions of the AIT. In addition, failure to take the actions addressed in the Confirmatory Action letter may result in enforcement action.
i
~ The responses directed by this letter are not subject to the clearance procedures of the Office of l
Management and Budget as required by the Paperwork Reduction Act of 1980, Pub. L.96-511.
I In accordance with 10 CFR 2.790 of the NRC's " Rules of Practice," a copy of this letter will be placed in the NRC Public Document Room. We appreciate your cooperation in this matter.
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Sincerely, ORIGINAL SIGNED BY:
i William F. Kane for:
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Thomas T. Martin Regional Administrator 4
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cc:
J.J.Hagan, Acting General Manager - Salem Operations 1
C. Schaefer, External Operations - Nuclear, Delmarva Power & Light Co.
S. LaBruna, Vice President - Engineering R.' Hovey, General Manager - Hope Creek Operations l
F. Thomson, Manager, Licensing and Regulation l
R. Swanson, General Manager - QA and Nuclear Safety Review
- J. Robb, Director, Joint Owner Affairs i
A. Tapert, Program Administrator i
R. Fryling, Jr., Esquire M. Wetterhahn, Esquire j
P. J. Curham, Manager, Joint Generation Department, l
Atlantic Electric Company j
Consumer Advocate, Office of Consumer Advocate j
William Conklin, Public Safety Consultant, lower Alloways Creek Township t
K. Abraham, PAO (2)
Public Document Room (PDR)
Local Public Document Room (LPDR)
I
~ Nuclear Safety Information Center (NSIC) l NRC Resident Inspector State of New Jersey l
4 1
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4 1
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4 a
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_.. -...~..-
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4 bec:
J. Taylor, EDO J. Lieberman, OE
. J. Milhoan, OEDO W. Kane, ORA, RI l
W. Russell, NRR R. Lanning, DRP, RI L. Reyes, NRR J. Durr, DRP, RI A. Thadani, NRR W. Hodges, DRS, RI J. Calvo, NRR J. Wiggins, DRS, RI C. Rossi, NRR R. Blough, DRS, RI l
i C. Miller, PD I-2, NRR C. Hehl, DRSS, RI l.
F. Miraglia, NRR S. Shankman, DRSS, RI l
C. Berlinger, NRR J. Stone, NRR W. Parler, OGC J. Wermeil, NRR l
B. Sheron, NRR E. Wenzinger, DRP, RI l
M. Virgilio, NRR J. White, DRP, RI l
B. Grimes, NRR R. Summers, DRP, RI B. Boger, NRR D. Chawaga, SLO, RI E. Jordon, AEOD D. Holody, EO, RI D. Ross, AEOD V. McCree, OEDO J. Larkins, ACRs P. Jefferson, DRMA, RI AIT Team Members i
I RI:DRP*
RI:DRP*
RI:DRP*
RI:DRP*
RI:EO*
NRR*
JWhite EWenzinger JDurr WLanning DHolody CMiller 4/ /94 4/ /94 4/ /94 4/ /94 4/ /94 4/ /94 RI:DRS*
RI:DRA RI:RA WHodges WKane TMartin 4/ /94 4/ /94 4/ /94 OFFICIAL RECORD COPY A: SALEM. CAL
- See Previous Concurrence j
i
- 1. -
5
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April 8,1994 i
MEMORANDUM FOR:
Marvin W. Hodges, Director, Division of Reactor Safety FROM:
Thomas T. Martin, Regional Administrator
}
SUBJECT:
AUGMENTED TEAM INSPECTION CHARTER FOR THE i
REVIEW OF THE SALEM UNIT NO.1 REACTOR SCRAM AND LOSS OF PRESSURIZER STEAM BUBBLE i
On April 7,1994, Salem Unit No. I reactor scrammed from 25% power during maneuvers to shut the plant down. Subsequent to the reactor scram, the plant experienced a series of safety-injections which resulted in loss of the pressurizer steam bubble and normal pressure control.
]
In addition to the reactor trip and safety injection, certain valves that are required to operate, failed to close. Because of multiple failures in safety related systems during the event and possible operator errors, per M.C. 325, Paragraph 05.02, Item a, I have determined that an Augmented Inspectwn Team (AIT) should be initiated to review the causes and safety
' implications associated with these malfunctions.
p i
The Division of Reactor Safety (DRS) is assigned the responsibility for the overall conduct of this augmented inspection. Robert Summers is appointed as the AIT leader. Other AIT members are identified in Enclosure 2.
The Division of Reactor Projects is assigned the responsibility for resident and clerical support as necessary; and the coordination with other NRC offices, as appropriate. Further, the Division of Reactor Safety, in coordination with DRP l
is responsible for the timely issuance of the inspection report, the identification and processing of potentially generic issues, and the identification and completion of any enforcement action warranted as a result of the team's review.
)
i represents the charter for the AIT and details the scope of the inspection. The inspection shall be conducted in accordance with NRC Management Directive 8.3, NRC j
inspection Manual 0325, inspection Procedure 93800, Regional Office Instruction 1010.1 and i
this memorandum.
f ORIGINAL SIGNED BY:
William F. Kane for j
Thomas T. Martin l
Regional Administrator
Enclosures:
- 1. Augmented Inspection Team Charter 4
- 2. Team Composition i
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2 bec:
C. Miller, NRR
- E. Wenzinger, DRP J. White, DRP C. Marschall, SRI J. Taylor, EDO T. Martin, RA I
l W. Kane, DRA i
W. Imning, DRP l
J. Durr, DRP l
J. Stone, NRR AIT Team Members i
l l
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i RI:DRP RI:DRP NRR RI:DRS RI:DRA JDURR WLANNING CMILLER WHODGES WKANE 4/ /94 4/ /94 4/ /94 4/ /94 4/ /94 OFFICIAL RECORD COPY G:AITSAL.JPD
t 7
ENCLOSURE 1 AUGMENTED INSPECTION TEAM CHARTER The general objectives of this AIT are to:
1.
Conduct a thorough and systematic review of the circumstances surrounding '1e reactor scram at Salem Unit No.1 on April 7,1994 and the resulting loss of the pressurizer steam bubble.
2.
Assess the operators'. actions preceding and subsequent to the reactor scram.
Develop a sequence of events and events causal factor analysis for the plant and operators' responses and human factors associated with the event. Compare the expected plant response to the actual plant responses.
3.
Review the licensees event classification and notifications for appropriate responses.
4.
Assess the safety significance of tne event and communicate to the regional and headquarters management the facts and safety concerns related to problem identified.
5.
Examine the equipment failures and identify associated root causes.
6.
Determine if any design vulnerabilities or deficiencies exist that warrant prompt actioft.
7.
Prepare a report documenting the results of this review for the Regional Administrator within thirty days of the completion of the inspection.
Schedule:
The AIT shall be dispatched to Salem so as to arrive and commence the inspection on April 8, 1994. During the site portion of the inspection resident and clerical support is available.
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8 ENCLOSURE 2 TEAM COMPOSITION The assigned team members are as follows:
Team Manager:
Wayne Hodges, DRS Onsite Team Leader:
Robert Summers, DRP Onsite Team Members:
Steve Barr, DRP Scott Stewart, DRS 12rry Scholl, DRS Warren Lyon, NRR Iqbal Ahmed, NRR John Kaufman, AEOD Howard Rathbun, NRR 1
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o & 1 & 94 13:34 U.S N.R.C. REGION 1 KIN 001 DCS No: 50272940407 j
Date: April 14,1994 1
l PRELIMINARY NOTIFICATION OF EVENT OR UNUSUAL OCCURRENCE PNl'-9425A i
This preliminary notification const]tutes EARLY notice of events of POSSIBLE safety or public interest significance. The information is as initially received without verification or evaluation, and is basically j
all that is known by the Region I staff on this date.
I Facility:
Licensee Emergency Classincation:
Salem Generating Station, Unit 1 Notification of Unasual Event J
Public Service Electric and Gas Co.
Alert Hancocks Bridge, New Jersey 08038 SJte Arca Emergency i
General Emergency i
_ XX_ Not Applicable I
Docket No.: 050-00272 l
License No.: DPR-70 j
Iivent No.:
I j
Event Location Code:
i
Subject:
Status' Report Update Fmm NRC Augmented Inspection Team j
The Augmented Inspection Team (AIT) remains onsite gathering data, conducting interviews, inspecting j
equipment, meeting with the licensee, concurring in licensee action plans and analyr.ing facts.
On 4-12-94, at 6:45 a.m., the Senior Resident Inspector noted that RVLIS channel A indicated 93%
reactor vessel level. Salem unit I was in cold shutdown, RCS temperature 173*F, RCS pressure 22 psig with all reactor coolant pumps (RCPs) off and one train o'f RHR operating at 3000 gpm flow. Contml j
room operators found that full range and upper range on both channels indicated 93% level (four i
indications total).. Although operators initially suspected instrument calibration problems, they j
subsequently concluded that the indicadon was accurate, that non-condensable gases had accumulated in i
the vessel head, and that the space occupied by the gases extended approximately 18 inches from the top l
of the reactor vessel head. They also found that reactor vessellevel had trended downward very slowly j_
since Saturday, when the RCPs were secured.
i As a result of identification of the gas volume, operators began hourly logging of RVLIS ludication, in j
addition to the normal logging of core exit thermocouple readings, RHR flow and pump amps, RCS.
temperature and pressure, charging flow and letdown flow. In addition, they opened the PORVs to vent the pressurizer, and reduced Volume Control Tank nitrogen cover gas pressure from about 40 psig to 15 j
psig. Water level (RVLIS) has been constant at about 90% since reducing VCT pressure, and the j
licensee does not perceive any immediate thmat to safety.
The licensee sampled the gas on 4/13 and found it to be 96% Nitrogen and 3% Hydrogen. The AIT will 1
inue to follow the licensce's actlyitics to determine the cause of the gas build-up in the head, and j
to vent the gas to support plant start-up, i
{
licensee issued a press release on 4/13, updating their intemal investigation results. Region 1 Pub!!c tirs is responding to media inquiries.
A'
- State of New Jersey has been notified.
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